Item 7. Management’s Discussion and Analysis
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Objective
The following discussion summarizes our results of operations and liquidity and capital resources for the fiscal years ended December 31, 2024 and 2023 and should be read in conjunction with our Consolidated Financial Statements and the accompanying notes included elsewhere in this Annual Report. A discussion of results of operations and liquidity and capital resources for fiscal year 2022 has been omitted from this report but may be found at “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the fiscal year ended December 31, 2023, filed with the SEC on February 22, 2024, and is incorporated by reference in this report from such prior Annual Report on Form 10-K. We intend for this discussion to provide the reader with information that will assist in understanding our consolidated financial statements, the changes in certain key items in those consolidated financial statements from period to period, and the primary factors that accounted for those changes.
2024 Overview
Our results during 2024 were mainly driven by increases in Royalty Properties sales volumes from continued drilling activity in the Permian Basin and Bakken region and incremental production from 2023 and 2024 acquisitions, offset by decreases in NPI sales volumes, leasing activity, and lower industrywide realized natural gas sales prices versus 2023. Significant results include the following:
●
Net income of $92.4 million;
●
Distributions of $146.5 million to our limited partners;
●
Acquisition of mineral, royalty, and overriding royalty interests in producing and non-producing oil and natural gas properties representing approximately 14,225 net mineral acres located in 14 counties across New Mexico and Texas in exchange for 6,721,144 common units representing limited partnership interests in the Partnership valued at $202.6 million and issued pursuant to the Partnership's registration statements on Form S-4;
●
Acquisition of overriding royalty interests representing approximately 1,204 net royalty acres located in Weld County, Colorado in exchange for 530,000 common units representing limited partnership interests in the Partnership valued at $16.0 million and issued pursuant to the Partnership's registration statement on Form S-4;
●
Acquisition of mineral interests representing approximately 1,485 net royalty acres located in two counties in Colorado in exchange for 505,369 common units representing limited partnership interests in the Partnership valued at $17.0 million and issued pursuant to the Partnership's registration statement on Form S-4; and
●
First payments on 1,943 gross and 12 net new wells on our Royalty Properties, of which 1,240 gross and eight net wells were attributable to our 2023 and 2024 acquisitions, and 146 gross and two net new wells on our NPI properties. The wells were located in 53 counties and parishes in eight states with the majority of the activity concentrated in the Permian Basin, Bakken region, South Texas, and the Rockies. Included in these totals are wells in which we own both a royalty interest and a net profits overriding royalty interest. Wells with such overlapping interests are counted in both categories.
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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 State (“U.S. GAAP”), which requires us to make certain estimates and apply judgments that affect our financial position and results of operations as reflected in our consolidated financial statements. Actual results may differ from those estimates. The Partnership’s accounting policies are summarized in Note 2 of the Notes to Consolidated Financial Statements in “Item 8 – Financial Statements and Supplementary Data”.
Management continually reviews our accounting policies, how they are applied, and how they are reported and disclosed in our consolidated financial statements. The following items require significant estimation or judgment:
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:
2024
2023
% Change
Royalty Properties natural gas sales (mmcf)
5,680
5,110
11
%
Royalty Properties oil sales (mbbls)
1,943
1,518
28
%
NPI natural gas sales (mmcf)
2,134
2,301
(7
)%
NPI oil sales (mbbls)
645
740
(13
)%
Accrual basis average sales price:
Royalty Properties natural gas sales ($/mcf)
$
1.37
$
2.39
(43
)%
Royalty Properties oil sales ($/bbl)
$
66.74
$
67.39
(1
)%
NPI natural gas sales ($/mcf)
$
1.54
$
2.65
(42
)%
NPI oil sales ($/bbl)
$
64.02
$
67.44
(5
)%
Comparison of the years ended December 31, 2024 and 2023
The increase in oil sales volumes attributable to our Royalty Properties during 2024 versus 2023 is primarily a result of higher suspense releases on new wells in the Permian Basin and Bakken region, suspense releases on first payments in the Permian Basin from wells acquired in the third quarter of 2024, higher suspense releases on first payments in the Rockies from wells acquired in the third quarter of 2024 and first quarters of 2024 and 2022, and increased baseline production in South Texas from wells acquired in 2023 and 2022, partially offset by lower suspense releases from first payments on acquired wells in South Texas and decreased baseline production in the Permian Basin, Bakken region, and the Rockies, particularly in the fourth quarter of 2024 compared to the same period of 2023. The increase in natural gas sales volumes attributable to our Royalty Properties during 2024 compared to 2023 is primarily attributable to higher baseline production and higher suspense releases on new wells in the Permian Basin, suspense releases on first payments in the Permian Basin from wells acquired in the third quarter of 2024, higher suspense releases on first payments in the Rockies from wells acquired in the first and third quarters of 2024, higher suspense releases on first payments and increased baseline production in East Texas from wells acquired in 2022, and increased baseline production in the Mid-Continent, partially offset by decreased baseline production and lower suspense releases from first payments on acquired wells in South Texas and decreased production from legacy wells in the Rockies, Fayetteville Shale, Barnett Shale, and Southeast.
The decrease in oil sales volumes attributable to our NPI properties during 2024 versus 2023 is primarily the result of lower suspense releases on new wells in the Permian Basin, partially offset by increased baseline production in the Permian Basin and Bakken region and higher suspense releases on new wells in the Bakken region. The decrease in natural gas sales volumes attributable to our NPI properties during 2024 compared to 2023 is primarily the result of lower suspense releases on new wells in the Permian Basin and Mid-Continent, partially offset by higher suspense releases on new wells in the Bakken region and increased baseline production in the Permian Basin, Bakken region, and Mid-Continent.
The decrease in lease bonus revenue from 2023 to 2024 is primarily attributable to receipt of $11.8 million from a lease and lease amendment transaction executed in 2023, wherein the Partnership leased 243 net acres in two tracts of land in Reagan County, Texas for $30,000 per acre and a 25% royalty and amended an existing lease on two separate tracts of land also totaling 243 net acres in Reagan County, Texas for $18,750 per acre.
Production taxes and operating expenses increased a combined 19% from 2023 to 2024. The increase is primarily a result of higher proportionate oil production taxes due to higher oil sales revenue attributable to our Royalty Properties and higher proportionate post-production costs, such as compression, transportation, processing, and marketing, due to higher oil and natural gas sales volumes attributable to our Royalty Properties.
Depreciation, depletion and amortization increased 62% from 2023 to 2024. Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of reserves extracted during such period, calculated on a units-of-production basis. Estimates of proved developed producing reserves are a major component in the calculation of depletion. We adjust our depletion rate each quarter for significant changes in our estimates of oil and natural gas reserves, including recent acquisitions and suspense releases on new wells.
General and administrative expenses increased 7% from 2023 to 2024. The increase is primarily attributable to higher compensation expenses due to market adjustments, increased bonuses and an expanded Equity Incentive Program designed for employee retention, and increased legal and other professional services fees, partially offset by a decrease resulting from one-time, non-recurring professional services expenses of $1.2 million related to an unsuccessful acquisition in the first nine months of 2023.
Net cash provided by operating activities decreased 5% from 2023 to 2024. The decrease is primarily due to lower NPI payment receipts and lower lease bonus receipts, partially offset by higher revenue receipts attributable to our Royalty Properties, net of production and operating expenses.
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Acquisitions for Units
On September 30, 2024, pursuant to a non-taxable contribution and exchange agreement with West Texas Minerals LLC, a Delaware limited liability company, Carrollton Mineral Partners, LP, a Texas limited partnership, Carrollton Mineral Partners Fund II, LP, a Texas limited partnership, Carrollton Mineral Partners III, LP, a Texas limited partnership, Carrollton Mineral Partners III-B, LP, a Texas limited partnership, Carrollton Mineral Partners IV, LP, a Texas limited partnership, CMP Permian, LP, a Texas limited partnership, CMP Glasscock, LP, a Texas limited partnership, and Carrollton Royalty, LP, a Texas limited partnership, the Partnership acquired mineral, royalty, and overriding royalty interests in producing and non-producing oil and natural gas properties representing approximately 14,225 net mineral acres located in 14 counties across New Mexico and Texas in exchange for 6,721,144 common units representing limited partnership interests in the Partnership valued at $202.6 million and issued pursuant to the Partnership’s registration statements on Form S-4. We believe that the acquisition is considered complementary to our business. The transaction was accounted for as an acquisition of assets under U.S. GAAP. Accordingly, the cost of the acquisition was allocated on a relative fair value basis and transaction costs were capitalized as a component of the cost of the assets acquired. Contributed cash delivered at closing and final settlement net cash received, net of capitalized transaction costs paid, of $8.8 million is included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended December 31, 2024.
On September 30, 2024, pursuant to a non-taxable contribution and exchange agreement with an unrelated third party, the Partnership acquired overriding royalty interests totaling approximately 1,204 net royalty acres located in Weld County, Colorado in exchange for 530,000 common units representing limited partnership interests in the Partnership valued at $16.0 million and issued pursuant to the Partnership’s registration statement on Form S-4. We believe that the acquisition is considered complementary to our business. The transaction was accounted for as an acquisition of assets under U.S. GAAP. Accordingly, the cost of the acquisition was allocated on a relative fair value basis and transaction costs were capitalized as a component of the cost of the assets acquired. Contributed cash delivered at closing and final settlement net cash received, net of capitalized transaction costs paid, of $1.4 million is included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended December 31, 2024.
On March 28, 2024, pursuant to a non-taxable contribution and exchange agreement with multiple unrelated third parties, the Partnership acquired mineral interests totaling approximately 1,485 net royalty acres located in two counties in Colorado in exchange for 505,369 common units representing limited partnership interests in the Partnership valued at $17.0 million and issued pursuant to the Partnership’s registration statement on Form S-4. We believe that the acquisition is considered complementary to our business. The transaction was accounted for as an acquisition of assets under U.S. GAAP. Accordingly, the cost of the acquisition was allocated on a relative fair value basis and transaction costs were capitalized as a component of the cost of the assets acquired. Contributed cash delivered at closing and final settlement net cash received, net of capitalized transaction costs paid, of $4.4 million is included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended December 31, 2024.
On September 29, 2023, pursuant to a non-taxable contribution and exchange agreement with an unrelated third party, the Partnership acquired mineral and royalty interests totaling approximately 716 net royalty acres located in three counties in Texas in exchange for 494,000 common units representing limited partnership interests in the Partnership valued at $14.4 million and issued pursuant to the Partnership’s registration statement on Form S-4. We believe that the acquisition is considered complementary to our business. The transaction was accounted for as an acquisition of assets under U.S. GAAP. Accordingly, the cost of the acquisition was allocated on a relative fair value basis and transaction costs were capitalized as a component of the cost of the assets acquired. Contributed cash delivered at closing and final settlement net cash received, net of capitalized transaction costs paid, of $0.9 million is included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended December 31, 2023.
On August 31, 2023, pursuant to a non-taxable contribution and exchange agreement with multiple unrelated third parties, the Partnership acquired mineral and royalty interests totaling approximately 568 net royalty acres located in three counties in Texas in exchange for 374,000 common units representing limited partnership interests in the Partnership valued at $10.4 million and issued pursuant to the Partnership’s registration statement on Form S-4. We believe that the acquisition is considered complementary to our business. The transaction was accounted for as an acquisition of assets under U.S. GAAP. Accordingly, the cost of the acquisition was allocated on a relative fair value basis and transaction costs were capitalized as a component of the cost of the assets acquired. Contributed cash delivered at closing and final settlement net cash received, net of capitalized transaction costs paid, of $0.3 million is included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended December 31, 2023. Final settlement net cash received, net of capitalized transaction costs paid, of $0.2 million is included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended December 31, 2024.
On July 12, 2023, pursuant to a non-taxable contribution and exchange agreement with multiple unrelated third parties, the Partnership acquired mineral and royalty interests totaling approximately 900 net royalty acres located in 13 counties and parishes across Louisiana, New Mexico, and Texas in exchange for 343,750 common units representing limited partnership interests in the Partnership valued at $11.0 million and issued pursuant to the Partnership’s registration statement on Form S-4. We believe that the acquisition is considered complementary to our business. The transaction was accounted for as an acquisition of assets under U.S. GAAP. Accordingly, the cost of the acquisition was allocated on a relative fair value basis and transaction costs were capitalized as a component of the cost of the assets acquired. Contributed cash delivered at closing and final settlement net cash received, net of capitalized transaction costs paid, of $0.5 million is included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended December 31, 2023.
On September 30, 2022, pursuant to a non-taxable contribution and exchange agreement with Excess Energy, LLC, a Texas limited liability company, the Partnership acquired mineral, royalty and overriding royalty interests totaling approximately 2,100 net royalty acres located in 12 counties across Texas and New Mexico in exchange for 816,719 common units representing limited partnership interests in the Partnership valued at $20.4 million and issued pursuant to the Partnership's registration statement on Form S-4. We believe that the acquisition is considered complementary to our business. The transaction was accounted for as an acquisition of assets under U.S. GAAP. Accordingly, the cost of the acquisition was allocated on a relative fair value basis and transaction costs were capitalized as a component of the cost of the assets acquired. Final settlement net cash received, net of capitalized transaction costs paid, of $0.5 million is included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended December 31, 2023.
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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 NPIs (other than cash proceeds received by the Partnership from a public or private offering of securities of the Partnership) less certain expenses and reasonable reserves. Additional cash requirements include the payment of oil and natural gas production and property taxes not otherwise deducted from gross production revenues and general and administrative expenses incurred on our behalf and allocated to the Partnership in accordance with the partnership agreement. Because the distributions to our unitholders are, by definition, determined after the payment of all expenses actually paid by us, the only cash requirements that may create liquidity concerns for us are the payment of expenses. Because many of these expenses vary directly with oil and natural gas sales prices and volumes, we anticipate that sufficient funds will be available at all times for payment of these expenses. See below for the dates of cash distributions to unitholders.
Contractual Obligations
The Partnership leases its office space at 3838 Oak Lawn Avenue, Suite 300, Dallas, Texas, through an operating lease (the “Office Lease”). The third amendment to our Office Lease was executed in April 2017 for a term of 129 months, beginning June 1, 2018 and expiring in 2029. Under the third amendment to the Office Lease, monthly rental payments range from $25,000 to $30,000. Future maturities of Office Lease liabilities representing monthly cash rental payment obligations are summarized in Note 7 of the Notes to Consolidated Financial Statements in “Item 8 – Financial Statements and Supplementary Data”.
We are not directly liable for the payment of any exploration, development or production costs. We do not have any transactions, arrangements or other relationships that could materially affect our liquidity or the availability of capital resources. We have not guaranteed the debt of any other party, nor do we have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt.
To the extent necessary to avoid unrelated business taxable income, our partnership agreement prohibits us from incurring indebtedness, excluding trade payables, in excess of $50,000 in the aggregate at any given time or which would constitute “acquisition indebtedness” (as defined in Section 514 of the Code).
We currently expect to have sufficient liquidity to fund our distributions to unitholders and operations despite potential material uncertainties that may impact us as a result of increased oil and natural gas market volatility caused by ongoing global military conflicts, global supply chain disruptions and the recent rise in inflation and interest rates. Although demand and market prices for oil and natural gas have remained strong due to the rising energy use and worldwide shortage of oil due to sanctions implemented on Russia, we cannot predict events that may lead to future price volatility. Our ability to fund future distributions to unitholders may be affected by the prevailing economic conditions in the oil and natural gas market and other financial and business factors, including the evolution of COVID-19 and any ongoing variants, along with the military conflict between Russia and Ukraine and the conflict between Israel and Hamas which are beyond our control. If market conditions were to change due to declines in oil prices or uncertainty created by COVID-19 or any ongoing variants and our revenues were reduced significantly or our operating costs were to increase significantly, our cash flows and liquidity could be reduced. Despite recent improvements, the current economic environment is volatile, and therefore, we cannot predict the ultimate impact that COVID-19, the ongoing military conflict between Russia and Ukraine or the ongoing conflict between Israel and Hamas will have on our liquidity or cash flows.
Liquidity and Working Capital
Cash and cash equivalents were $42.5 million as of December 31, 2024 and $47.0 million as of December 31, 2023.
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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
2023
4th
January 29, 2024
February 8, 2024
$
1.007874
$
39,895
$
1,517
2024
1st
April 29, 2024
May 9, 2024
$
0.781837
31,343
1,092
2024
2nd
July 29, 2024
August 8, 2024
$
0.702058
28,144
974
2024
3rd
October 28, 2024
November 7, 2024
$
0.995785
47,140
1,776
Total distributions paid in 2024
$
146,522
$
5,359
2024
4th
February 3, 2025
February 13, 2025
$
0.739412
$
35,004
$
1,291
In general, the limited partners are allocated 96% of the Royalty Properties’ net receipts and 99% of NPI net receipts.
Net Profits Interest
We receive monthly payments from the Operating Partnership equal to 96.97% of the net proceeds realized by the Operating Partnership from the properties underlying the Net Profits Interest (or “NPI”). The Operating Partnership retains the 3.03% balance of these net proceeds. Net proceeds generally reflect gross proceeds attributable to oil and natural gas production actually received during the month, less production costs actually paid during the same month, net of budgeted capital expenditures. Production costs generally reflect drilling, completion, operating and general and administrative costs and exclude depletion, amortization and other non-cash costs. The Operating Partnership made NPI payments to us totaling $23.9 million during October 2023 through September 2024, which payments reflected 96.97% of total net proceeds of $24.6 million realized from September 2023 through August 2024. Net proceeds realized by the Operating Partnership during September through November 2024 were reflected in NPI payments made during October through December 2024. These payments were included in the fourth quarter distribution paid February 13, 2024 and are excluded from this 2024 analysis.
Royalty Properties
Revenues from the Royalty Properties are typically paid to us with proportionate severance (production) taxes deducted and remitted by others. Additionally, we generally pay ad valorem taxes, general and administrative costs, and marketing and associated costs because royalties and lease bonuses generally do not otherwise bear operating or similar costs. After deduction of the costs described above, including cash reserves, our net cash receipts from the Royalty Properties during October 2023 through September 2024 were $128.0 million, of which $122.9 million (96%) was distributed to the limited partners and $5.1 million (4%) was distributed to the General Partner. Proceeds received by us from the Royalty Properties during October through December 2024 became part of the fourth quarter distribution paid in early 2025, which is excluded from this 2024 analysis.
Distribution Determinations
The actual calculation of distributions is performed each calendar quarter in accordance with our partnership agreement. The following calculation covering the period October 2023 through September 2024 demonstrates the method:
In Thousands
Limited
General
Partners
Partner
4% of net cash receipts from Royalty Properties
$
-
$
5,120
96% of net cash receipts from Royalty Properties
122,879
-
1% of NPI payments to our Partnership
-
239
99% of NPI payments to our Partnership
23,643
-
Total distributions
$
146,522
$
5,359
Operating Partnership share (3.03% of net proceeds)
746
Total General Partner share
$
6,105
% of total
96
%
4
%
In summary, our limited partners received 96%, and our General Partner received 4% of the net cash generated by our activities and those of the Operating Partnership during this period. Due to these fixed percentages, our General Partner does not have any incentive distribution rights or other right or arrangement that will increase its percentage share of net cash generated by our activities or those of the Operating Partnership.
During the period October 2023 through September 2024, our Partnership's quarterly distribution payments to limited partners were based on all of its available cash, as defined in "Item 1 – Business".
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Fourth Quarter 2024 Distribution Indicated Price
In an effort to provide information concerning prices of oil and natural gas sales that correspond to our quarterly distributions, management calculates the average price by dividing gross revenues received by the net volumes of the corresponding product without regard to the timing of the production to which such sales may be attributable. This “indicated price” does not necessarily reflect the contractual terms for such sales and may be affected by transportation costs, location differentials, and quality and gravity adjustments. While the relationship between the Partnership's cash receipts and the timing of the production of oil and natural gas may be described generally, actual cash receipts may be materially impacted by purchasers’ release of suspended funds and by prior period adjustments.
Cash receipts attributable to the Partnership's Royalty Properties during the 2024 fourth quarter totaled $34.9 million. Approximately 68% of these receipts reflect oil sales during September 2024 through November 2024 and natural gas sales during August 2024 through October 2024, and approximately 32% from prior sales periods. The average indicated prices for oil and natural gas sales attributable to the Royalty Properties during the 2024 fourth quarter were $64.25/bbl and $1.22/mcf, respectively.
Cash receipts attributable to the Partnership's NPI during the 2024 fourth quarter totaled $5.4 million. Approximately 61% of these receipts reflect oil and natural gas sales during August 2024 through October 2024, and approximately 39% from prior sales periods. The average indicated prices for oil and natural gas sales attributable to the NPI were $63.93/bbl and $1.24/mcf, respectively.
General and Administrative Costs
In accordance with our partnership agreement, we bear all general and administrative and other overhead expenses subject to certain limitations. We reimburse our General Partner for certain allocable costs, including rent, wages, salaries and employee benefit plans that are not direct expenses. This reimbursement is limited to an amount equal to the sum of 5% of our distributions plus certain costs previously paid. For the year ended December 31, 2024, the reimbursement amounts actually paid or reserved did not exceed the limitation.
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