What changed in this filing

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Item 2. Management’s Discussion and Analysis

2024-11-05 compared with 2024-08-06 · 88 added, 88 removed, 301 unchanged (37% of the section changed)

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Alongside our primary focus on traditional revenue streams from our asset base, we will continue to explore the relevance of our assets in energy transition, including opportunities in renewable energy and carbon sequestration.

As of June 30, 2024, our mineral and royalty interests were located in 41 states in the continental United States, including all of the major onshore producing basins.

As of September 30, 2024, our mineral and royalty interests were located in 41 states in the continental United States, including all of the major onshore producing basins.

These non-cost-bearing interests include ownership in approximately 68,000 producing wells.

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Shelby Trough Development Update

A significant portion of Shelby Trough development in recent years has been performed by Aethon Energy (“Aethon”) under the two Joint Exploration Agreements (“JEAs”) between us and Aethon.

In the first half of 2024, revenues from Aethon's operations in the Shelby Trough made up 6% of our total revenues.

The JEAs outline Aethon’s development obligations and other rights and obligations of each party related to our core mineral positions in San Augustine and Angelina counties in East Texas.

Under the JEAs, Aethon may elect to temporarily suspend its drilling obligations for up to nine consecutive months and a maximum of 18 total months in any 48-month period when natural gas prices fall below specified thresholds.

When the "time-out" provision is invoked, the current program year under each agreement is paused during the suspension period such that the program year may extend beyond 12 calendar months.

In December 2023, we received notice that Aethon was exercising the time-out provisions under the JEAs in San Augustine and Angelina, implying a maximum resumption date in September 2024.

Aethon drilled three wells in the first quarter of 2024 in San Augustine county despite the invocation of the time-out and has brought 16 total wells online in the first half of 2024.

During the second quarter, we continued working with Aethon to firm up future development plans in light of Aethon's previously announced invocation of a time-out.

Austin Chalk Update

We remain focused on full field development, which includes working with multiple operators on drilling and field optimization opportunities in the Brookeland Field to enhance production and increase reserves from the Austin Chalk formation.

In September 2024, we entered into letter agreements with Aethon Energy ("Aethon") to amend the Joint Exploration Agreements ("JEAs") in San Augustine and Angelina counties.

In those agreements, the parties agreed to revise the current program year drill schedules under each JEA, to extend the respective program years by nine months, and to withdraw the invocation of the time-out provisions.

Aethon also released its rights under 25,000 acres from the parties' area of mutual interest defined in the original JEAs.

Upon the satisfaction of the current program year performance deadlines as described in the letter agreements, Aethon will have an inventory of ten banked wells in Angelina and one banked well in San Augustine.

Business Environment

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Oil and natural gas prices have been historically volatile based upon the dynamics of supply and demand.

To manage the variability in cash flows associated with the projected sale of our oil and natural gas production, we use various derivative instruments, which have recently consisted of fixed-price swap contracts.

Oil prices increased from the prior period ended June 30, 2023 as a result of heightened geopolitical risk related to the attacks targeting commercial ships transiting the Red Sea shipping channel and general elevated tensions around the region.

In addition, the recent extension of OPEC+ voluntary production cuts add to upward price pressure at a time of the year when oil demand typically increases because of the spring and summer driving seasons in the Northern Hemisphere.

Natural gas prices increased during the second quarter of 2024 because of less natural gas-directed drilling and production curtailments due to low natural gas prices in the first quarter of 2024 as a result of a large surplus of storage inventory.

The United States started the winter heating season with a surplus and a mild winter led to below average consumption, further increasing the surplus of storage inventory.

Given the dynamic nature of these events, along with the volatile geopolitical conflicts in Ukraine, we cannot reasonably estimate how long these market conditions will persist.

To manage the variability in cash flows associated with the projected sale of our oil and natural gas production, we use various derivative

instruments, which have recently consisted of fixed-price swap contracts.

While oil inventories continued to decline in the third quarter of 2024, oil prices decreased during the period because of offsetting concerns that the market would continue to be oversupplied in 2025 without additional growth in demand.

OPEC+ members' decision to delay production increases until December 2024 is expected to lead to further reductions in global inventories and is reflective of the lingering impact of rising global inventories experienced in 2023.

Heightened geopolitical risk related to continued conflict in the Middle East has increased the possibility for future supply disruptions and price volatility.

Natural gas prices decreased sharply in the fourth quarter of 2023 and the first quarter of 2024 as a result of a large surplus of storage inventory.

Less natural gas-directed drilling and production curtailments led to increased natural gas prices in the second quarter of 2024 which continued to recover in the third quarter of 2024 due to hot summer temperatures and the related increase in U.S.

electricity demand across all sectors.

An increase in LNG exports with the addition of capacity further added to natural gas price increases in the third quarter of 2024.

Given the dynamic nature of these events, along with the volatile geopolitical conflicts in Ukraine and the Middle East, we cannot reasonably estimate how long these market conditions will persist.

While we use derivative instruments to partially mitigate the impact of commodity price volatility, our revenues and operating results depend significantly upon the prevailing prices for oil and natural gas.

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Benchmark Prices 1

Second Quarter First Quarter Second Quarter First Quarter

Third Quarter Second Quarter First Quarter Third Quarter Second Quarter First Quarter

WTI spot oil price ($/Bbl) $ 68.75 $ 82.83 $ 83.96 $ 90.77 $ 70.66 $ 75.68

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Rotary Rig Count 1

Second Quarter First Quarter Second Quarter First Quarter

Third Quarter Second Quarter First Quarter Third Quarter Second Quarter First Quarter

Oil 484 479 506 502 545 592

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The portion of production used for storage varies from year to year depending on the demand from the previous winter and the demand for electricity used for cooling during the summer months.

The EIA expects inventories will rise to 4.0 Tcf at the end of October 2024, which would be 6% higher than the five-year average.

Energy Information Administration ("EIA") estimates that natural gas inventories concluded the injection season in October 2024 at 3.9 Tcf, which is 4% higher than the five-year average.

The following table shows natural gas storage volumes by region at the end of each quarter presented:

Second Quarter First Quarter Second Quarter First Quarter

Third Quarter Second Quarter First Quarter Third Quarter Second Quarter First Quarter

East 846 660 363 847 643 335

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Natural Gas Exports

Net natural gas exports averaged 11.9 Bcf per day during the first half of 2024, consistent with the average for the full year of 2023.

The EIA expects U.S.

LNG exports will increase as LNG export projects come on line in late 2024 and mid-2025.

Net natural gas exports averaged 11.5 Bcf per day during the third quarter of 2024, a 3% decrease from the 2023 average.

The EIA forecasts average exports of 13.2 Bcf per day for the remainder of 2024 and 13.8 Bcf per day for 2025.

The EIA forecast reflects assumptions that U.S.

LNG exports will increase as LNG export projects come on line in late 2024 and mid-2025.

How We Evaluate Our Operations

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If commodity prices decline in the future, our hedging contracts will partially mitigate the effect of lower prices on our future revenue.

Our open oil and natural gas derivative contracts as of June 30, 2024 are detailed in Note 4 - Commodity Derivative Financial Instruments to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

Our open oil and natural gas derivative contracts as of September 30, 2024 are detailed in Note 4 - Commodity Derivative Financial Instruments to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

Pursuant to the terms of our Credit Facility, we are allowed to hedge certain percentages of expected future monthly production volumes equal to the lesser of (i) internally forecasted production and (ii) the average of reported production for the most recent three months.

We are allowed, but not required, to hedge, using swaps and collars with a term of no more than four years, up to 90% of our expected future volumes for the first 24 months, 70% for months 25 through 36, and 50% for months 37 through 48.

As of June 30, 2024, we had hedged 72% and 71% of our available oil and condensate hedge volumes for 2024 and 2025, respectively.

As of June 30, 2024, we had also hedged 69% and 66% of our available natural gas hedge volumes for 2024 and 2025, respectively.

As of September 30, 2024, we had hedged 75% and 71% of our available oil and condensate hedge volumes for 2024 and 2025, respectively.

As of September 30, 2024, we had also hedged 77% and 79% of our available natural gas hedge volumes for 2024 and 2025, respectively.

We intend to continuously monitor the production from our assets and the commodity price environment, and will, from time to time, add additional hedges within the percentages described above related to such production.

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The following table presents a reconciliation of net income (loss), the most directly comparable GAAP financial measure, to Adjusted EBITDA and Distributable cash flow for the periods indicated:

Three Months Ended June 30, Six Months Ended June 30,

Three Months Ended September 30, Nine Months Ended September 30,

2024 2023 2024 2023

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Unrealized (gain) loss on commodity derivative instruments (20,811) 51,111 21,642 29,006

(Gain) loss on sale of assets, net — (73) — (73)

Adjusted EBITDA 86,442 130,015 290,806 349,188

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Results of Operations

Three Months Ended June 30, 2024 Compared to Three Months Ended June 30, 2023

Three Months Ended September 30, 2024 Compared to Three Months Ended September 30, 2023

The following table shows our production, revenue, and operating expenses for the periods presented:

Three Months Ended June 30,

Three Months Ended September 30,

2024 2023 Variance

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however, revenue attributable to NGLs is included in our natural gas revenue and our calculation of realized prices for natural gas.

Total revenue for the quarter ended June 30, 2024 decreased compared to the quarter ended June 30, 2023.

The decrease in total revenue in the second quarter of 2024 is primarily due to a loss on our commodity derivative instruments compared to a gain in the corresponding prior period and a decrease in natural gas and NGL sales, which were partially offset by an increase in oil and condensate sales.

Total revenue for the quarter ended September 30, 2024 increased compared to the quarter ended September 30, 2023.

The increase in total revenue in the third quarter of 2024 is primarily due to a gain on our commodity derivative instruments compared to a loss in the corresponding prior period, which were partially offset by a decrease in natural gas, NGL, oil, and condensate sales.

Oil and condensate sales.

Oil and condensate sales increased for the quarter ended June 30, 2024 as compared to the corresponding period in 2023 primarily due to higher production volumes and realized commodity prices.

The increase in oil and condensate production was driven by higher mineral and royalty production in the Permian Basin.

Our mineral and royalty interest oil and condensate volumes accounted for 95% and 93% of total oil and condensate volumes for quarters ended June 30, 2024 and 2023, respectively.

Oil and condensate sales decreased for the quarter ended September 30, 2024 as compared to the corresponding period in 2023 primarily due to lower production volumes and realized commodity prices.

The decrease in oil and condensate production was driven by reduced mineral and royalty production in the Permian Basin.

Our mineral and royalty interest oil and condensate volumes accounted for 95% and 96% of total oil and condensate volumes for quarters ended September 30, 2024 and 2023, respectively.

Natural gas and natural gas liquids sales.

Natural gas and NGL sales decreased for the quarter ended June 30, 2024 as compared to the corresponding prior period.

The decrease was due to lower realized commodity prices between the comparative periods partially offset by an increase in production volumes.

The increase in production volumes was driven by an increase in royalty interest production volumes, primarily within the Haynesville/Bossier play, including 29 new wells coming online from the Aethon development program in the Shelby Trough subsequent to the second quarter of 2023.

Mineral and royalty interest production accounted for 94% and 93% of our natural gas volumes for the quarters ended June 30, 2024 and 2023, respectively.

Natural gas and NGL sales decreased for the quarter ended September 30, 2024 as compared to the corresponding prior period.

The decrease was due to lower realized commodity prices between the comparative periods and a reduction in production volumes.

The decrease in natural gas and NGL production was driven by lower mineral and royalty production in the Haynesville/Bossier play trend.

Mineral and royalty interest production accounted for 94% and 94% of our natural gas volumes for the quarters ended September 30, 2024 and 2023, respectively.

Gain (loss) on commodity derivative instruments.

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The changes in fair value result from new positions and settlements that may occur during each reporting period, as well as the relationships between contract prices and the associated forward curves.

During the second quarter of 2024, we recognized a loss from our commodity derivative instruments compared to a gain in the same period in 2023.

For the three months ended June 30, 2024, we recognized $11.8 million of realized gains and $17.4 million of unrealized losses from our oil and natural gas commodity contracts, compared to $28.2 million of realized gains and $16.9 million of unrealized losses in the same period in 2023.

The unrealized losses on our commodity contracts during the second quarters of 2024 and 2023 were primarily driven by changes in the forward commodity price curves for natural gas.

During the third quarter of 2024, we recognized a gain from our commodity derivative instruments compared to a loss in the same period in 2023.

For the three months ended September 30, 2024, we recognized $10.9 million of realized gains and $20.8 million of unrealized gains from our oil and natural gas commodity contracts, compared to $24.2 million of realized gains and $51.1 million of unrealized losses in the same period in 2023.

The unrealized gains on our commodity contracts during the third quarters of 2024 and the unrealized losses in the corresponding period in 2023 were primarily driven by changes in the forward commodity price curves for oil and natural gas.

Lease bonus and other income.

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Lease bonus revenue can vary substantively between periods because it is derived from individual transactions with operators, some of which may be significant.

Lease bonus and other income for the second quarter of 2024 was higher than the same period in 2023.

Leasing activity in the Permian Basin made up the majority of lease bonus and other income for the second quarter of 2024, while the majority of the second quarter 2023 activity came from leasing activity in the Bakken/Three Forks and Haynesville/Bossier plays.

Lease bonus and other income for the third quarter of 2024 was lower than the same period in 2023.

Leasing activity in the Bakken/Three Forks made up the majority of lease bonus and other income for the third quarter of 2024, while the majority of the third quarter 2023 activity came from leasing activity in the Bakken/Three Forks and Haynesville/Bossier plays.

Operating Expenses

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Lease operating expense includes recurring expenses associated with our non-operated working interests necessary to produce hydrocarbons from our oil and natural gas wells, as well as certain nonrecurring expenses, such as well repairs.

Lease operating expense decreased for the quarter ended June 30, 2024 as compared to the same period in 2023, primarily due to lower nonrecurring service-related expenses, including workovers.

Lease operating expense decreased for the quarter ended September 30, 2024 as compared to the same period in 2023, primarily due to lower nonrecurring service-related expenses, including workovers.

Production costs and ad valorem taxes .

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Rates, methods of calculating property values, and timing of payments vary between taxing authorities.

For the quarter ended June 30, 2024, production costs and ad valorem taxes increased as compared to the quarter ended June 30, 2023, primarily due to higher production taxes stemming from increased production volumes.

For the quarter ended September 30, 2024, production costs and ad valorem taxes decreased as compared to the quarter ended September 30, 2023, primarily due to lower production taxes stemming from lower commodity prices and decreased production volumes.

Exploration expense .

Exploration expense typically consists of dry-hole expenses, delay rentals, and geological and geophysical costs, including seismic costs, and is expensed as incurred under the successful efforts method of accounting.

Exploration expense for the quarter ended June 30, 2024 and the corresponding prior period of 2023 was minimal.

Exploration expense typically consists of dry-hole expenses, payments for delay rentals where the Partnership is the lessee, and geological and geophysical costs, including seismic costs, and is expensed as incurred under the successful efforts method of accounting.

For the quarter ended September 30, 2024, exploration expenses increased compared to the same period in 2023, primarily due to an increase in seismic purchases and delay rentals.

Depreciation, depletion, and amortization .

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We adjust our depletion rates semi-annually based upon mid-year and year-end reserve reports, except when circumstances indicate that there has been a significant change in reserves or costs.

Depreciation, depletion, and amortization increased for the quarter ended June 30, 2024 as compared to the same period in 2023 due to higher production volumes.

Depreciation, depletion, and amortization decreased for the quarter ended September 30, 2024 as compared to the same period in 2023 due to lower production volumes.

General and administrative .

General and administrative expenses are costs not directly associated with the production of oil and natural gas and include expenses such as the cost of employee salaries and related benefits, office expenses, and fees for professional services.

For the quarter ended June 30, 2024, general and administrative expenses increased as compared to the same period in 2023, primarily due to an increase in cash compensation driven by an increase in salaries as well as a separation payment related to the departure of a senior executive.

For the quarter ended September 30, 2024, general and administrative expenses decreased as compared to the same period in 2023, primarily due to a decrease in consulting costs and equity-based compensation, partially offset by an increase in salaries.

The decrease in equity-based compensation was due to lower costs recognized for performance-based incentive awards resulting from downward movements in our common unit price during the quarter ended September 30, 2024 compared to upward movements in the corresponding prior period.

Interest expense .

Interest expense in the second quarter of 2024 was consistent with the corresponding period in 2023 with minimal average outstanding borrowings under our Credit Facility during each period.

Interest expense in the third quarter of 2024 increased as compared to the corresponding period in 2023, with minimal average outstanding borrowings under our Credit Facility during each period.

Interest expense for both periods primarily consisted of commitment fees and amortization of debt issuance costs.

Six Months Ended June 30, 2024 Compared to Six Months Ended June 30, 2023

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023

The following table shows our production, revenues, pricing, and expenses for the periods presented:

Six Months Ended June 30,

Nine Months Ended September 30,

2024 2023 Variance

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however, revenue attributable to NGLs is included in our natural gas revenue and our calculation of realized prices for natural gas.

Total revenue for the six months ended June 30, 2024 decreased compared to the corresponding prior period.

The decrease in total revenue is primarily due to a loss on our commodity derivative instruments compared to a gain in the corresponding prior period and a decrease in natural gas and NGL sales, which were partially offset by an increase in oil and condensate sales.

Total revenue for the nine months ended September 30, 2024 decreased compared to the corresponding prior period.

The decrease in total revenue is primarily due to a reduced gain on our commodity derivative instruments compared to the gain in the corresponding prior period and a decrease in natural gas and NGL sales, which were partially offset by an increase in oil and condensate sales.

Oil and condensate sales.

Oil and condensate sales during the six months ended June 30, 2024 increased compared to the corresponding prior period primarily due to higher production volumes and realized commodity prices.

The increase in oil and condensate production was driven by mineral and royalty production in the Permian Basin.

Our mineral and royalty interest oil and condensate volumes accounted for 94% and 93% of total oil and condensate volumes for the six months ended June 30, 2024 and 2023, respectively.

Oil and condensate sales during the nine months ended September 30, 2024 slightly increased compared to the corresponding prior period primarily due to higher production volumes.

Our mineral and royalty interest oil and condensate volumes accounted for 95% and 94% of total oil and condensate volumes for the nine months ended September 30, 2024 and 2023, respectively.

Natural gas and natural gas liquids sales.

Natural gas and NGL sales during the six months ended June 30, 2024 decreased compared to the corresponding prior period due to lower realized commodity prices partially offset by higher production volumes.

Mineral and royalty interest production accounted for 95% and 94% of our natural gas volumes for the six months ended June 30, 2024 and 2023, respectively.

Natural gas and NGL sales during the nine months ended September 30, 2024 decreased compared to the corresponding prior period due to lower realized commodity prices.

Mineral and royalty interest production accounted for 94% and 94% of our natural gas volumes for the nine months ended September 30, 2024 and 2023, respectively.

Gain (loss) on commodity derivative instruments.

During the six months ended June 30, 2024, we recognized a loss from our commodity derivative instruments compared to a gain for the same period in 2023.

In the six months ended June 30, 2024, we recognized $25.6 million of realized gains and $42.5 million of unrealized losses from our oil and natural gas commodity contracts, compared to $41.5 million of realized gains and $22.1 million of unrealized gains in the same period in 2023.

The unrealized losses on our commodity contracts during the six months ended June 30, 2024 and the unrealized gains in the corresponding period in 2023 were primarily driven by changes in the forward commodity price curves for oil and natural gas.

During the nine months ended September 30, 2024, we recognized a reduced gain from our commodity derivative instruments as compared to the gain recognized for the same period in 2023.

In the nine months ended September 30, 2024, we recognized $36.4 million of realized gains and $21.6 million of unrealized losses from our oil and natural gas commodity contracts, compared to $65.7 million of realized gains and $29.0 million of unrealized losses in the same period in 2023.

The unrealized losses on our commodity contracts during the nine months ended September 30, 2024 and the corresponding period in 2023 were primarily driven by changes in the forward commodity price curves for oil and natural gas.

Lease bonus and other income.

Lease bonus and other income for the six months ended June 30, 2024 was higher than the same period in 2023.

Leasing activity in the Permian Basin and the Austin Chalk play trend and proceeds from surface use waivers on our mineral acreage supporting solar development in Texas composed the majority of lease bonus and other income for the six months ended June 30, 2024, while a substantial portion of the activity in the corresponding prior period came from leasing activity in the Bakken/Three Forks and Haynesville/Bossier plays.

Lease bonus and other income for the nine months ended September 30, 2024 was higher than the same period in 2023.

Leasing activity in the Permian Basin, Bakken/Three Forks, and the Austin Chalk plays and proceeds from surface use waivers on our mineral acreage supporting solar development in Texas composed the majority of lease bonus and other income for the nine months ended September 30, 2024, while a substantial portion of the activity in the corresponding prior period came from leasing activity in the Bakken/Three Forks and Haynesville/Bossier plays.

Operating and Other Expenses

Lease operating expense .

Lease operating expense decreased for the six months ended June 30, 2024 as compared to the same period in 2023, primarily due to lower nonrecurring service-related expenses, including workovers.

Lease operating expense decreased for the nine months ended September 30, 2024 as compared to the same period in 2023, primarily due to lower nonrecurring service-related expenses, including workovers.

Production costs and ad valorem taxes .

For the six months ended June 30, 2024, production costs and ad valorem taxes increased as compared to the six months ended June 30, 2023, primarily due to an increase in production taxes from higher oil commodity prices and production volumes.

For the nine months ended September 30, 2024, production costs and ad valorem taxes decreased as compared to the nine months ended September 30, 2023, primarily due to a decrease in production taxes from lower oil and natural gas commodity prices.

Exploration expense .

Exploration expense was minimal for the six months ended June 30, 2024 and for the six months ended June 30, 2023.

For the nine months ended September 30, 2024 exploration expenses increased compared to the same period in 2023, primarily due to an increase in seismic purchases and delay rentals.

Depreciation, depletion, and amortization .

Depreciation, depletion, and amortization increased for the six months ended June 30, 2024 as compared to the same period in 2023, primarily due to increased production volumes.

Depreciation, depletion, and amortization slightly increased for the nine months ended September 30, 2024 as compared to the same period in 2023, primarily due to increased production volumes.

General and administrative .

For the six months ended June 30, 2024, general and administrative expenses increased as compared to the same period in 2023, primarily due to higher professional costs related to outside legal fees, consulting costs for internal projects, and cash compensation.

For the nine months ended September 30, 2024, general and administrative expenses increased as compared to the same period in 2023, primarily due to higher professional costs related to outside legal fees, consulting costs for internal projects, and cash compensation, partially offset by a decrease in equity-based compensation.

The increase in cash compensation was driven by increases in salaries and costs recognized under our short-term cash incentive plan.

The decrease in equity-based compensation was due to lower costs recognized for performance-based incentive awards resulting from downward movements in our common unit price during the nine months ended September 30, 2024 compared to upward movements in the corresponding prior period.

Interest expense .

Interest expense was lower in the six months ended June 30, 2024 than in the prior period primarily due to lower average outstanding borrowings under our Credit Facility.

Interest expense was lower in the nine months ended September 30, 2024 than in the prior period primarily due to lower average outstanding borrowings under our Credit Facility.

Liquidity and Capital Resources

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The following table shows our cash flows for the periods presented:

Six Months Ended June 30,

Nine Months Ended September 30,

2024 2023 Change

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Our operating cash flows are dependent, in large part, on our production, realized commodity prices, derivative settlements, lease bonus revenue, and operating expenses.

Cash flows provided by operating activities decreased for the six months ended June 30, 2024 as compared to the same period of 2023.

The decrease was primarily due to reduced natural gas and NGL sales due to lower realized commodity prices partially offset by higher oil sales.

The overall decrease was also due to a reduction in cash received on the settlement of commodity derivatives in the six months ended June 30, 2024 compared to the same period of 2023.

Cash flows provided by operating activities decreased for the nine months ended September 30, 2024 as compared to the same period of 2023.

The decrease was primarily due to lower natural gas and NGL sales stemming from lower realized commodity prices and a reduction in cash received on the settlement of commodity derivatives in the nine months ended September 30, 2024 compared to the same period of 2023.

Investing Activities .

Net cash used in investing activities in the six months ended June 30, 2024 increased as compared to the same period of 2023.

The increase was primarily due to acquisitions of oil and natural gas properties in the six months ended June 30, 2024 as compared to no acquisition activity in the corresponding prior period.

Net cash used in investing activities in the nine months ended September 30, 2024 increased as compared to the same period of 2023.

The increase was primarily due to acquisitions of oil and natural gas properties in the nine months ended September 30, 2024 as compared to minimal acquisition activity in the corresponding prior period.

Financing Activities .

Cash flows used in financing activities decreased for the six months ended June 30, 2024 as compared to the same period of 2023.

The decrease was primarily due to lower distributions paid to unitholders and no net repayments on our Credit Facility for the six months ended June 30, 2024 compared to net repayments for the six months ended June 30, 2023.

Cash flows used in financing activities decreased for the nine months ended September 30, 2024 as compared to the same period of 2023.

The decrease was primarily due to lower distributions paid to unitholders and no net repayments on our Credit Facility for the nine months ended September 30, 2024 compared to net repayments for the nine months ended September 30, 2023.

Development Capital Expenditures

Our 2024 capital expenditure budget associated with our non-operated working interests is expected to be approximately $2.3 million, net of farmout reimbursements, of which $0.4 million has been invested in the six months ended June 30, 2024.

Our 2024 capital expenditure budget associated with our non-operated working interests is expected to be approximately $2.3 million, net of farmout reimbursements, of which $0.7 million has been invested in the nine months ended September 30, 2024.

The majority of this capital is anticipated to be spent on workovers and recompletions on existing wells in which we own a working interest.

Through June 30, 2024, we have also spent $1.8 million acquiring leases in areas around our drilling programs.

During the six months ended June 30, 2024, we acquired mineral and royalty interests that consisted of primarily unproved oil and natural gas properties from various sellers for an aggregate of $50.5 million, including capitalized direct transaction costs.

Through September 30, 2024, we have also spent $1.8 million acquiring leases in areas around our drilling programs.

During the nine months ended September 30, 2024, we acquired mineral and royalty interests that consisted of primarily unproved oil and natural gas properties from various sellers for an aggregate of $65.2 million, including capitalized direct transaction costs.

The consideration paid consisted of $64.2 million in cash that was funded from operating activities and $1.0 million in equity that was funded through the issuance of common units of the Partnership based on the fair values of the common units issued on the acquisition dates.

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See "Note 3 – Oil and Natural Gas Properties" to the unaudited interim consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information.

Asset Exchange

In the third quarter of 2024, we closed on a transaction with a third-party operator whereby we received an oil and natural gas lease on approximately 8,000 net leasehold acres in East Texas in exchange for the assignment of approximately 51,000 undeveloped net mineral and royalty acres in Mississippi.

Credit Facility

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The April 2023 borrowing base redetermination reaffirmed the borrowing base at $550.0 million.

The subsequent redeterminations increased the borrowing base to $580.0 million in October 2023 and reaffirmed the borrowing base in April 2024.

The subsequent redeterminations increased the borrowing base to $580.0 million in October 2023 and reaffirmed the borrowing base in April 2024 and November 2024.

After each redetermination we elected to maintain cash commitments at $375.0 million.

The next semi-annual redetermination is scheduled for October 2024.

The next semi-annual redetermination is scheduled for April 2025.

We are subject to various affirmative, negative, and financial maintenance covenants which pose limitations on future borrowings, leases, hedging, and sales of assets.

As of June 30, 2024, we were in compliance with all debt covenants.

As of September 30, 2024, we were in compliance with all debt covenants.

See "Note 6 – Credit Facility" to the unaudited interim consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information.

Contractual Obligations

As of June 30, 2024, there have been no material changes to our contractual obligations previously disclosed in our 2023 Annual Report on Form 10-K.

As of September 30, 2024, there have been no material changes to our contractual obligations previously disclosed in our 2023 Annual Report on Form 10-K.

Critical Accounting Policies and Related Estimates

As of June 30, 2024, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our 2023 Annual Report on Form 10-K.

As of September 30, 2024, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our 2023 Annual Report on Form 10-K.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-Q

Item 2. Management’s Discussion and Analysis