What changed in this filing

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Item 2. Management’s Discussion and Analysis

2024-05-07 compared with 2023-10-31 · 93 added, 164 removed, 228 unchanged (53% of the section changed)

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We are one of the largest owners and managers of oil and natural gas mineral interests in the United States.

Our principal business is maximizing the value of our existing portfolio of mineral and royalty assets through active management and expanding our asset base through acquisitions of additional mineral and royalty interests.

We maximize value through marketing our mineral assets for lease, creatively structuring the terms on those leases to encourage and accelerate drilling activity, and selectively participating alongside our lessees on a working interest basis.

Our principal business is maximizing the value of our existing portfolio of mineral and royalty assets through active management.

We maximize value through marketing our mineral assets for lease and creatively structuring the terms on those leases to encourage and accelerate drilling activity.

We believe our large, diversified asset base and long-lived, non-cost-bearing mineral and royalty interests provide for stable production and reserves over time, allowing the majority of generated cash flow to be distributed to unitholders.

As of September 30, 2023, 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 over 68,000 producing wells.

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 March 31, 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.

We also own non-operated working interests, a significant portion of which are on our positions where we also have a mineral and royalty interest.

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Shelby Trough Development Update

Aethon continues to perform with drilling and completing wells according to our development agreements.

Aethon has six rigs currently on our acreage in the Shelby Trough.

As of September 30, 2023, Aethon has successfully turned 18 wells to sales and has commenced operations on 27 additional wells under the development agreement covering Angelina County.

As of September 30, 2023, Aethon has successfully turned ten wells to sales and has another seven wells awaiting completion operations under the separate development agreement covering San Augustine County.

Additionally, XTO Energy has two wells currently awaiting completion operations.

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.

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.

In December 2023, we received notice that Aethon was exercising the “time-out” provisions under these JEAs.

When natural gas prices fall below specified thresholds, 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.

Aethon has not previously invoked the time-out provisions under the JEAs.

We continue working closely with Aethon to finalize development plans going forward and assess the effect of the temporary suspension of drilling obligations, and we are analyzing the potential impacts to us on an ongoing basis.

In April 2024, Aethon began curtailing production volumes on a small number of producing wells.

This temporary decrease is expected to amount to approximately 800 Boe/d.

Additionally, Aethon has indicated that it intends to curtail these

wells and delay the initial production of an additional 10 wells until the second half of the year, when natural gas prices are forecast to improve.

Austin Chalk Update

We have entered into agreements with multiple operators to drill wells in the areas of the Austin Chalk in East Texas, where we have significant acreage positions.

The results of the 2021 three well test program in the Brookeland Field demonstrated that modern completion technology has the potential to greatly improve production rates and increase reserves when compared to the vintage, unstimulated wells in the Austin Chalk formation.

Eight operators are actively engaged in redevelopment of the field.

As of September 30, 2023, 26 wells with modern completions are now producing in the field, and an additional three wells are currently either being drilled or completed.

The results of the test program in the Brookeland Field demonstrated that modern completion technology has the potential to improve production rates and increase reserves when compared to the vintage, unstimulated wells in the Austin Chalk formation.

To date, 30 wells with modern completions are being produced in the field.

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.

Average commodity prices during the nine months ended September 30, 2023 decreased from the corresponding prior period, due to several factors, including reduced demand for natural gas and rising global oil inventories.

Natural gas prices decreased sharply in the fourth quarter of 2022 and the first quarter of 2023 as a result of increases in dry natural gas production, lower-than-average consumption due to mild winter weather conditions, and the resulting higher-than-average storage inventories.

Natural gas prices began to recover in the next two quarters as production growth has not kept pace with the growth in LNG exports and record consumption in the electric power sector this summer.

Despite lower-than-average storage injections in the third quarter, natural gas inventories remain above the five-year average, and the U.S.

Energy Information Administration ("EIA") expects natural gas supplies will be sufficient to meet winter demand.

For much of the nine months ended September 30, 2023, oil prices were lower than the corresponding prior period.

In September 2023, oil prices increased after Saudi Arabia extended its voluntary crude oil production cuts through the end of the year and U.S.

commercial crude oil inventories fell to the lowest levels since early 2022.

The EIA expects reduced production targets by members of the Organization of the Petroleum Exporting Countries and its broader partners ("OPEC+") to continue during 2024 with offsetting production growth from non-OPEC+ producers.

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

Oil prices increased from the prior period ended March 31, 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 decreased from the prior period ended March 31, 2023 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.

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

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

First Quarter First Quarter

WTI spot oil price ($/Bbl) $ 83.96 $ 75.68

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Rotary Rig Count 1

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

Oil 502 545 592 604 594 531

First Quarter First Quarter

Natural gas 112 160

Other 5 5 3 2 2 2

Total 621 755

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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 estimates that natural gas inventories concluded the injection season in October 2023 at 3.9 Tcf, which is 6% higher than the previous five-year average.

The EIA expects inventories will rise to 4.1 Tcf at the end of October 2024, which would be 10% higher than the five-year average.

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

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

East 847 643 335 756 461 268

First Quarter First Quarter

Midwest 510 421

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Natural Gas Exports

The EIA expects an increase in U.S.

LNG exports resulting from three LNG export projects that are set to begin operations in 2024.

Net natural gas exports averaged 11.4 Bcf per day in the third quarter of 2023, a 7% increase from the 2022 average.

The EIA forecasts average exports of 11.9 Bcf per day for the remainder of 2023 and 13.1 Bcf per day for 2024.

The EIA forecast reflects the assumption that production remains flat and that expected additional U.S.

LNG export capacity comes online.

The EIA expects exports of natural gas, both by pipeline and as LNG, will increase in 2024.

The EIA forecasts average exports of 12.2 Bcf per day for 2024, a 2% increase from 2023 levels.

In 2025, the EIA expects LNG exports to increase because three of the five LNG export projects currently under construction are expected to start operations and ramp up to full production.

The EIA also expects natural gas exports by pipeline to grow because of increased natural gas exports to Mexico.

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 September 30, 2023 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 March 31, 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 up to 90% of such volumes for the first 24 months, 70% for months 25 through 36, and 50% for months 37 through 48.

As of September 30, 2023, we had hedged 67% and 56% of our available oil and condensate hedge volumes for 2023 and 2024, respectively.

As of September 30, 2023, we had also hedged 63% and 77% of our available natural gas hedge volumes for 2023 and 2024, respectively.

We are allowed, but not required, to hedge, using collars and swaps 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 March 31, 2024, we had hedged 72% and 71% of our available oil and condensate hedge volumes for 2024 and 2025, respectively.

As of March 31, 2024, we had also hedged 69% and 60% 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 September 30, Nine Months Ended September 30,

2023 2022 2023 2022

Three Months Ended March 31,

(in thousands)

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Unrealized (gain) loss on commodity derivative instruments 25,087 (38,986)

(Gain) loss on sale of assets, net (73) — (73) (17)

Adjusted EBITDA 104,117 109,928

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Results of Operations

Three Months Ended September 30, 2023 Compared to Three Months Ended September 30, 2022

Three Months Ended March 31, 2024 Compared to Three Months Ended March 31, 2023

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

Three Months Ended September 30,

Three Months Ended March 31,

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 September 30, 2023 decreased compared to the quarter ended September 30, 2022.

The decrease in total revenue from the corresponding period is primarily due to a decrease in natural gas and NGL sales and a larger loss from our commodity derivative instruments, and was partially offset by a small increase in oil and condensate sales.

Total revenue for the quarter ended March 31, 2024 decreased compared to the quarter ended March 31, 2023.

The decrease in total revenue in the first 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 was partially offset by an increase in oil and condensate sales.

Oil and condensate sales.

Oil and condensate sales increased for the quarter ended September 30, 2023 as compared to the corresponding period in 2022 primarily due to higher production volumes partially offset by lower realized commodity prices.

The increase in oil and condensate production was driven by increases in mineral and royalty production in the Permian Basin, the Bakken Shale, and the Eagle Ford.

Our mineral and royalty interest oil and condensate volumes accounted for 96% and 94% of total oil and condensate volumes for quarters ended September 30, 2023 and 2022, respectively.

Oil and condensate sales increased for the quarter ended March 31, 2024 as compared to the corresponding period in 2023 primarily due to higher production volumes.

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 94% and 92% of total oil and condensate volumes for quarters ended March 31, 2024 and 2023, respectively.

Natural gas and natural gas liquids sales.

Natural gas and NGL sales decreased for the quarter ended September 30, 2023 as compared to the corresponding prior period.

The decrease was primarily due to lower realized commodity prices between the comparative periods.

Mineral and royalty interest production accounted for 94% and 93% of our natural gas volumes for the quarters ended September 30, 2023 and 2022, respectively.

Natural gas and NGL sales decreased for the quarter ended March 31, 2024 as compared to the corresponding prior period.

The decrease was due to lower realized commodity prices between the comparative periods.

Mineral and royalty interest production accounted for 95% and 94% of our natural gas volumes for the quarters ended March 31, 2024 and 2023, respectively.

Gain (loss) on commodity derivative instruments.

During the third quarter of 2023, we recognized a larger loss from our commodity derivative instruments compared to the same period in 2022.

Cash settlements we receive represent realized gains, while cash settlements we pay represent realized losses related to our 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.

For the three months ended September 30, 2023, we recognized $24.2 million of realized gains and $51.1 million of unrealized losses from our oil and natural gas commodity contracts, compared to $68.9 million of realized losses and $64.1 million of unrealized gains in the same period in 2022.

The unrealized losses on our commodity contracts during the third quarter of 2023 and the unrealized gains in the same period in 2022 were primarily driven by changes in the forward commodity price curves for oil.

During the first 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 March 31, 2024, we recognized $13.8 million of realized gains and $25.1 million of unrealized losses from our oil and natural gas commodity contracts, compared to $13.3 million of realized gains and $39.0 million of unrealized gains in the same period in 2023.

The unrealized losses on our commodity contracts during the first quarter of 2024 were primarily driven by changes in the forward commodity price curves for oil and the unrealized gains in the same period in 2023 were driven by changes in the forward commodity price curves for 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 third quarter of 2023 was lower than the same period in 2022.

Leasing activity in the Haynesville/Bossier and Bakken/Three Forks plays made up the majority of lease bonus and other income for the third quarter of 2023, while the majority of the third quarter 2022 activity came from leasing activity in the Haynesville/Bossier play and the Permian Basin.

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

Leasing activity in the Austin Chalk play and proceeds from surface use waivers on our mineral acreage supporting solar development in Texas made up the majority of lease bonus and other income for the first quarter of 2024, while the majority of the first quarter 2023 activity came from leasing activity in the Haynesville/Bossier play and the Permian Basin.

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 September 30, 2023 as compared to the same period in 2022, primarily due to lower nonrecurring service-related expenses, including workovers.

Lease operating expense decreased for the quarter ended March 31, 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 September 30, 2023, production costs and ad valorem taxes decreased as compared to the quarter ended September 30, 2022, primarily due to lower commodity prices and ad valorem tax estimates.

For the quarter ended March 31, 2024, production costs and ad valorem taxes increased as compared to the quarter ended March 31, 2023, primarily due to severance tax refunds received in the first quarter of 2023 with no similar activity recorded in the first quarter of 2024.

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 September 30, 2023 primarily related to costs incurred to acquire seismic information related to our mineral and royalty interests.

Exploration expense in the corresponding prior period of 2022 was minimal.

Exploration expense for the quarter ended March 31, 2024 and the corresponding prior period of 2023 was minimal.

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 was unchanged for the quarter ended September 30, 2023 as compared to the same period in 2022.

Depreciation, depletion, and amortization increased for the quarter ended March 31, 2024 as compared to the same period in 2023 due to higher 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 September 30, 2023, general and administrative expenses increased as compared to the same period in 2022, primarily due to a $1.3 million increase in consulting costs related to internal projects.

Interest expense .

Interest expense was lower in the third quarter of 2023 relative to the corresponding period in 2022, due to no borrowings under our Credit Facility.

Interest expense for the third quarter of 2023 consisted of commitment fees and amortization of debt issuance costs.

Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022

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

Nine Months Ended September 30,

2023 2022 Variance

(Dollars in thousands, except for realized prices)

Oil and condensate (MBbls) 2,731 2,574 157 6.1 %

Natural gas (MMcf) 1

48,101 42,648 5,453 12.8 %

Equivalents (MBoe) 10,748 9,682 1,066 11.0 %

Equivalents/day (MBoe) 39.4 35.5 3.9 11.0 %

Realized prices, without derivatives:

Oil and condensate ($/Bbl) $ 76.23 $ 97.27 $ (21.04) (21.6) %

Natural gas ($/Mcf) 1

3.07 7.61 (4.54) (59.7) %

Equivalents ($/Boe) $ 33.13 $ 59.39 $ (26.26) (44.2) %

Oil and condensate sales $ 208,184 $ 250,367 $ (42,183) (16.8) %

Natural gas and natural gas liquids sales 1

147,857 324,691 (176,834) (54.5) %

Lease bonus and other income 8,682 10,262 (1,580) (15.4) %

Revenue from contracts with customers 364,723 585,320 (220,597) (37.7) %

Gain (loss) on commodity derivative instruments 36,652 (152,095) 188,747 124.1 %

Total revenue $ 401,375 $ 433,225 $ (31,850) (7.4) %

Operating expenses:

Lease operating expense $ 8,149 $ 9,256 $ (1,107) (12.0) %

Production costs and ad valorem taxes 41,952 51,309 (9,357) (18.2) %

Exploration expense 1,719 192 1,527 795.3 %

Depreciation, depletion, and amortization 33,935 35,018 (1,083) (3.1) %

General and administrative 38,950 39,326 (376) (1.0) %

Other expense:

Interest expense 2,080 4,264 (2,184) (51.2) %

1 As a mineral and royalty interest owner, we are often provided insufficient and inconsistent data on NGL volumes by our operators.

As a result, we are unable to reliably determine the total volumes of NGLs associated with the production of natural gas on our acreage.

Accordingly, no NGL volumes are included in our reported production;

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 nine months ended September 30, 2023 decreased compared to the corresponding prior period.

The decrease in total revenue is due to decreases in natural gas and NGL sales, oil and condensate sales, and lease bonus and other income which were partially offset by a gain from our commodity derivative instruments for the nine months ended September 30, 2023 compared to a loss in the same period in 2022.

Oil and condensate sales.

Oil and condensate sales during the nine months ended September 30, 2023 decreased compared to the corresponding prior period due to lower realized commodity prices that were partially offset by an increase in production.

The increase in oil and condensate production was driven by mineral and royalty production in the Bakken Shale, the Permian Basin and the Eagle Ford.

Our mineral and royalty interest oil and condensate volumes accounted for 94% and 93% of total oil and condensate volumes for the nine months ended September 30, 2023 and 2022, respectively.

Natural gas and natural gas liquids sales.

Natural gas and NGL sales during the nine months ended September 30, 2023 decreased compared to the corresponding prior period due to lower realized commodity prices partially offset by higher production volumes.

The increase in natural gas and NGL production was driven by increases in royalty interest production volumes, primarily within the Haynesville/Bossier play, including new activity from the Aethon development program in the Shelby Trough.

Mineral and royalty interest production accounted for 94% and 91% of our natural gas volumes for the nine months ended September 30, 2023 and 2022, respectively.

Gain (loss) on commodity derivative instruments.

During the nine months ended September 30, 2023, we recognized a gain from our commodity derivative instruments compared to a loss for the same period in 2022.

In the nine months ended September 30, 2023, we recognized $65.7 million of realized gains and $29.0 million of unrealized losses from our oil and natural gas commodity contracts, compared to $162.6 million of realized losses and $10.5 million of unrealized gains in the same period in 2022.

The unrealized losses on our commodity contracts during the nine months ended September 30, 2023 and the unrealized gains in the corresponding period in 2022 were primarily driven by changes in the forward commodity price curves for oil.

Lease bonus and other income.

Lease bonus and other income for the nine months ended September 30, 2023 was lower than the same period in 2022.

Leasing activity in the Haynesville/Bossier and Bakken/Three Forks plays made up the majority of lease bonus and other income for the nine months ended September 30, 2023, while a substantial portion of the activity in the corresponding prior period came from leasing activity in the Haynesville/Bossier play and the Permian Basin.

Operating and Other Expenses

Lease operating expense .

Lease operating expense decreased for the nine months ended September 30, 2023 as compared to the same period in 2022, primarily due to lower nonrecurring service-related expenses, including workovers.

Production costs and ad valorem taxes .

For the nine months ended September 30, 2023, production costs and ad valorem taxes decreased as compared to the nine months ended September 30, 2022, primarily due to lower commodity prices and lower ad valorem tax estimates.

Exploration expense .

Exploration expense for the nine months ended September 30, 2023 primarily related to costs incurred to acquire seismic information related to our mineral and royalty interests.

Exploration expense in the corresponding prior period of 2022 was minimal.

Depreciation, depletion, and amortization .

Depreciation, depletion, and amortization decreased slightly for the nine months ended September 30, 2023 as compared to the same period in 2022, primarily due to a reduction in cost basis with a lower corresponding reduction in proved developed producing reserve quantities partially offset by increased production.

The reduction in cost basis is primarily due to depreciation, depletion, and amortization recorded during the prior twelve months.

General and administrative .

For the nine months ended September 30, 2023, general and administrative expenses decreased as compared to the same period in 2022, primarily due to a $3.4 million decrease in equity compensation which was partially offset by a $1.4 million increase in cash compensation and a $1.4 million increase in consulting costs related to internal projects.

The decrease in equity incentive compensation was due to lower costs recognized for performance-based incentive awards resulting from upward movements in our common unit price in the corresponding prior period.

The increase in cash compensation was driven by an increase in salaries and a separation payment related to the departure of a senior executive in the first quarter of 2023.

This increase was partially offset by lower costs recognized under our short-term cash incentive plan due to projected outperformance relative to performance targets in the prior period.

For the quarter ended March 31, 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 the timing of annual tax services performed.

Interest expense .

Interest expense was lower in the nine months ended September 30, 2023 than in the prior period primarily due to lower average outstanding borrowings under our Credit Facility.

Interest expense was lower in the first quarter of 2024 relative to the corresponding period in 2023, due to lower average outstanding borrowings under our Credit Facility.

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

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated from operations, borrowings under our Credit Facility, and proceeds from the issuance of equity and debt.

Our primary uses of cash are for distributions to our unitholders, reducing outstanding borrowings under our Credit Facility, and for investing in our business, specifically the acquisition of mineral and royalty interests and our selective participation on a non-operated working interest basis in the development of our oil and natural gas properties.

As of September 30, 2023, no balance was outstanding under the Credit Facility.

Beginning on November 28, 2023, we have the option to redeem Series B cumulative convertible preferred units.

Also effective November 28, 2023, and every two years thereafter (each, a "Readjustment Date"), the distribution rate for the Series B cumulative convertible preferred units will be adjusted to the greater of (i) the distribution rate in effect immediately prior to the relevant Readjustment Date and (ii) the 10-year Treasury Rate as of such Readjustment Date plus 5.5% per annum.

Our primary sources of liquidity are cash generated from operations and borrowings under our Credit Facility.

Our primary uses of cash are for distributions to our unitholders, reducing outstanding borrowings under our Credit Facility, and for investing in our business.

On November 28, 2023 the distribution rate for the Series B cumulative convertible preferred units was adjusted to 9.8% and will be readjusted every two years thereafter (each, a "Readjustment Date").

The rate set on each Readjustment Date is equal to the greater of (i) the distribution rate in effect immediately prior to the relevant Readjustment Date and (ii) the 10-year Treasury Rate as of such Readjustment Date plus 5.5% per annum.

We have the option to redeem all or a portion (equal to or greater than $100 million) of the Series B cumulative convertible preferred units for a 90 day period beginning on each Readjustment Date at a redemption price of $20.39 per Series B cumulative convertible preferred unit, which is equal to par value.

See "Note 9 - Preferred Units" to the unaudited interim consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information.

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The Board may change the foregoing distribution policy at any time and from time to time.

We intend to finance any future acquisitions with cash generated from operations, borrowings from our Credit Facility, proceeds from any future issuances of equity and debt, and proceeds from asset sales.

We intend to finance any future acquisitions with cash generated from operations, borrowings from our Credit Facility, and proceeds from any future issuances of equity and debt.

Over the long-term, we intend to finance our working interest capital needs with our executed farmout agreements and internally generated cash flows, although at times we may fund a portion of these expenditures through other financing sources such as borrowings under our Credit Facility.

On October 30, 2023, the Board authorized a $150.0 million unit repurchase program which authorizes us to make repurchases on a discretionary basis.

The program will be funded from our cash on hand or through borrowings under the Credit Facility.

Any repurchased units will be cancelled.

See "Note 11 – Common Units" to the unaudited interim consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information.

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

Nine Months Ended September 30,

Three Months Ended March 31,

2024 2023 Change

1 unchanged sentence

Cash flows provided by operating activities $ 104,460 $ 137,155 $ (32,695)

Cash flows used in investing activities (4,946) (677) (4,269)

Cash flows used in financing activities (330,466) (275,911) (54,555)

Cash flows provided by (used in) investing activities (23,964) (1,954) (22,010)

Cash flows provided by (used in) financing activities (110,322) (120,358) 10,036

Operating Activities .

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 increased for the nine months ended September 30, 2023 as compared to the same period of 2022.

The increase was primarily due to higher cash settlements received on our commodity derivative instruments as compared to cash settlements paid in the same period of 2022.

Cash flows provided by operating activities decreased for the three months ended March 31, 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 in the three months ended March 31, 2024 compared to the same period of 2023.

Investing Activities .

Net cash used in investing activities in the nine months ended September 30, 2023 increased as compared to the same period of 2022.

The increase was primarily due to increased additions to oil and natural gas properties, net of farmout reimbursements in the nine months ended September 30, 2023 as compared to the corresponding prior period.

Net cash used in investing activities in the three months ended March 31, 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 three months ended March 31, 2024 as compared to no acquisition activity in the corresponding prior period.

Financing Activities .

Cash flows used in financing activities increased for the nine months ended September 30, 2023 as compared to the same period of 2022.

The increase was primarily due to higher distributions to unitholders in the nine months ended September 30, 2023 as compared to the corresponding prior period.

Cash flows used in financing activities decreased for the three months ended March 31, 2024 as compared to the same period of 2023.

The decrease was primarily due to net repayments on our Credit Facility for the three months ended March 31, 2023 compared to no net repayments for the three months ended March 31, 2024.

Development Capital Expenditures

Our 2023 capital expenditure budget associated with our non-operated working interests is expected to be approximately $4.1 million, net of farmout reimbursements, of which $3.7 million has been invested in the nine months ended September 30, 2023.

The majority of this capital is for our participation in a single well drilled on our mineral acreage in the Austin Chalk play

trend as part of our organic initiatives in the area.

The remaining capital is for workovers and recompletions on existing wells in which we own a working interest.

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 $0.3 million has been invested in the three months ended March 31, 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 March 31, 2024, we have also spent $0.7 million acquiring leases in areas around our drilling programs.

During the three months ended March 31, 2024, we acquired mineral and royalty interests that consisted of substantially all unproved oil and natural gas properties from various sellers for cash consideration of $23.0 million, including capitalized direct transaction costs.

These acquisitions were primarily located in the Gulf Coast land region and were funded with cash from operating activities.

Our current commercial strategy includes the continuation of meaningful, targeted mineral and royalty acquisitions to complement our existing positions.

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.

Credit Facility

We maintain a senior secured revolving credit agreement, as amended, (the "Credit Facility").

The Credit Facility has an aggregate maximum credit amount of $1.0 billion.

The Credit Facility has an aggregate maximum credit amount of $1.0 billion and terminates on October 31, 2027.

The commitment of the lenders equals the least of the aggregate maximum credit amount, the then-effective borrowing base, and the aggregate elected commitment, as it may be adjusted from time to time.

The amount of the borrowing base is redetermined semi-annually, usually in April and October.

In October 2022, we revised and amended the Credit Facility to extend the maturity date from November 1, 2024 to October 31, 2027.

Concurrent with the Credit Facility amendment, the borrowing base under the Credit Facility was increased to $550.0 million and we elected to lower commitments under the Credit Facility from $400.0 million to $375.0 million.

The April 2023 borrowing base redetermination reaffirmed the borrowing base at $550.0 million with cash commitments at $375.0 million.

The October 2023 borrowing base redetermination increased the borrowing base to $580.0 million with no change to the cash commitments.

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

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

As of September 30, 2023, we were in compliance with all debt covenants.

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.

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

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

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 March 31, 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 September 30, 2023, there have been no material changes to our contractual obligations previously disclosed in our 2022 Annual Report on Form 10-K.

As of March 31, 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 September 30, 2023, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our 2022 Annual Report on Form 10-K.

As of March 31, 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