What changed in this filing

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Item 2. Management’s Discussion and Analysis

2023-10-31 compared with 2023-08-01 · 95 added, 110 removed, 297 unchanged (41% of the section changed)

41 unchanged sentences

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 June 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.

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.

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

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

Aethon has successfully turned 16 wells to sales and has commenced operations on 18 additional wells under the development agreement covering Angelina County.

Aethon has successfully turned six wells to sales and has another nine wells awaiting completion operations under the separate development agreement covering San Augustine County.

Additionally, XTO Energy has turned four wells to sales in the second quarter and has two wells currently awaiting completion operations.

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.

Austin Chalk Update

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Eight operators are actively engaged in redevelopment of the field.

We have also reached an agreement with one of these operators to drill 10 wells in the field over the next two years.

To date, 26 wells with modern completions are now producing in the field, and an additional three wells are currently either being drilled or completed.

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.

Business Environment

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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.

Commodity prices during the six months ended June 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 in the first quarter of 2023 and remained flat in the second quarter as a result of increases in dry natural gas production, lower-than-average consumption due to mild winter weather conditions in the first two months of the year, and the resulting higher-than-average storage inventories.

The current price environment remains uncertain as responses to elevated inflation and the conflict in Ukraine continue to evolve.

The EIA expects relatively flat U.S.

natural gas production and year-over-year growth in consumption in the electric power sector to raise prices in the second half of 2023.

Given the dynamic nature of these events, we cannot reasonably estimate the period of time that these market conditions will persist.

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.

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) $ 90.77 $ 70.66 $ 75.68 $ 79.91 $ 107.76 $ 100.53

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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 502 545 592 604 594 531

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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 will conclude the injection season in October 2023 at 3.9 Tcf, which is 7% higher than the previous five-year average.

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 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 847 643 335 756 461 268

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The EIA expects an increase in U.S.

LNG exports resulting from two major LNG export projects under construction that will come online by the end of 2024.

Net natural gas exports averaged 12.1 Bcf per day in the second quarter of 2023, a 14% increase from the 2022 average.

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.

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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, 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 September 30, 2023 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 June 30, 2023, we had hedged 74% and 62% of our available oil and condensate hedge volumes for 2023 and 2024, respectively.

As of June 30, 2023, we had also hedged 67% and 82% of our available natural gas hedge volumes for 2023 and 2024, respectively.

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 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,

2023 2022 2023 2022

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Results of Operations

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

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

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

Three Months Ended June 30,

Three Months Ended September 30,

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

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

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.

Oil and condensate sales.

Oil and condensate sales decreased for the quarter ended June 30, 2023 as compared to the corresponding period in 2022 primarily due to lower realized commodity prices and production volumes.

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

Our mineral and royalty interest oil and condensate volumes accounted for 93% and 92% of total oil and condensate volumes for quarters ended June 30, 2023 and 2022, respectively.

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.

Natural gas and natural gas liquids sales.

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

The decrease was primarily due to lower realized commodity prices between the comparative periods partially offset by higher production volumes due to the timing of new development.

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

Mineral and royalty interest production accounted for 93% and 90% of our natural gas volumes for the quarters ended June 30, 2023 and 2022, respectively.

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.

Gain (loss) on commodity derivative instruments.

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

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 June 30, 2023, we recognized $28.2 million of realized gains and $16.9 million of unrealized losses from our oil and natural gas commodity contracts, compared to $62.5 million of realized losses and $35.1 million of unrealized gains in the same period in 2022.

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

The unrealized gains for the same period in 2022 were primarily driven by changes in the forward commodity price curves for natural gas.

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.

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 2023 was higher than the same period in 2022.

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

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.

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, 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 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 .

4 unchanged sentences

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

For the quarter ended June 30, 2023, production costs and ad valorem taxes decreased as compared to the quarter ended June 30, 2022, primarily due to lower production taxes and lower ad valorem tax estimates stemming from lower commodity prices.

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.

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 was minimal for the quarter ended June 30, 2023 and in the corresponding prior period in 2022.

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.

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 decreased for the quarter ended June 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.

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

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, 2023, general and administrative expenses decreased slightly as compared to the same period in 2022, primarily due to a $0.8 million decrease in cash compensation.

The decrease in cash compensation was driven by projected underperformance relative to performance targets under our short-term cash incentive plan compared with projected overperformance in the prior period.

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 second quarter of 2023 relative to the corresponding period in 2022, primarily due to lower average outstanding borrowings under our Credit Facility.

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022

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:

Six Months Ended June 30,

Nine Months Ended September 30,

2023 2022 Variance

29 unchanged sentences

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, 2023 increased compared to the corresponding prior period.

The increase in total revenue is due to a gain from our commodity derivative instruments for the six months ended June 30, 2023 compared to a loss in the same period in 2022.

The overall increase in total revenue was partially offset by decreases in oil and condensate sales, natural gas and NGL sales, and lease bonus and other income.

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 six months ended June 30, 2023 decreased compared to the corresponding prior period due to lower realized commodity prices and a decrease in production.

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

Our mineral and royalty interest oil and condensate volumes accounted for 93% of total oil and condensate volumes for both the six months ended June 30, 2023 and 2022.

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 six months ended June 30, 2023 decreased compared to the corresponding prior period due to lower realized commodity prices partially offset by higher production volumes.

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 89% of our natural gas volumes for the six months ended June 30, 2023 and 2022, respectively.

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

In the six months ended June 30, 2023, we recognized $41.5 million of realized gains and $22.1 million of unrealized gains from our oil and natural gas commodity contracts, compared to $93.7 million of realized losses and $53.7 million of unrealized losses in the same period in 2022.

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

The unrealized losses on our commodity contracts during the corresponding period in 2022 were primarily driven by changes in the forward commodity price curves for oil and natural gas.

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 six months ended June 30, 2023 was lower than the same period in 2022.

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

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 six months ended June 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 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 six months ended June 30, 2023, production costs and ad valorem taxes decreased as compared to the six months ended June 30, 2022, primarily due to lower production taxes stemming from lower commodity prices and lower ad valorem tax estimates.

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 was minimal for the six months ended June 30, 2023 and for the six months ended June 30, 2022.

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 six months ended June 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.

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 six months ended June 30, 2023, general and administrative expenses decreased as compared to the same period in 2022, primarily due to a $2.6 million decrease in equity compensation which was partially offset by a $1.0 million increase in cash compensation.

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

The overall increase in cash compensation was partially offset by projected underperformance relative to performance targets under our short-term cash incentive plan compared with projected overperformance in the prior period.

The decrease in equity incentive compensation was due to lower costs recognized for performance-based incentive awards resulting from downward movements in our common unit price during the six months ended June 30, 2023 compared to upward movements in our common unit price in the corresponding prior period.

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.

Interest expense .

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

Liquidity and Capital Resources

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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 June 30, 2023, no balance was outstanding under the Credit Facility.

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

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

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.

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.

The Board has adopted a policy pursuant to which, at a minimum, distributions will be paid on each common unit for each quarter to the extent we have sufficient cash generated from our operations after establishment of cash reserves, if any, and after we have made the required distributions to the holders of our outstanding preferred units.

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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,

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

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.

Investing Activities .

Net cash used in investing activities in the six months ended June 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 six months ended June 30, 2023 as compared to the corresponding prior period.

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.

Financing Activities .

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

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

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.

Development Capital Expenditures

Our 2023 capital expenditure budget associated with our non-operated working interests is expected to be approximately $4.9 million, net of farmout reimbursements, of which $2.5 million has been invested in the six months ended June 30, 2023.

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

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.

Credit Facility

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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.

Borrowings under the Credit Facility may be used for the acquisition of properties, cash distributions, and other general corporate purposes.

Our Credit Facility terminates on October 31, 2027.

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

The borrowing base is redetermined semi-annually, usually in April and October and is derived from the value of our oil and natural gas properties as determined by the lender syndicate using pricing assumptions that often differ from the current market for future prices.

We and the lenders (at the direction of two-thirds of the lenders) each have discretion to request a borrowing base redetermination one time between scheduled redeterminations.

We also have the right to request a redetermination following the acquisition of oil and natural gas properties in excess of 10% of the value of the borrowing base immediately prior to such acquisition.

The borrowing base is also adjusted if we terminate our hedge positions or sell oil and natural gas property interests that have a combined value exceeding 5% of the current borrowing base.

In these circumstances, the borrowing base will be adjusted by the value attributed to the terminated hedge positions or the oil and natural gas property interests sold in the most recent borrowing base.

The April and October 2021 and April 2022 borrowing base redeterminations reaffirmed the borrowing base at $400.0 million.

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.

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

The next semi-annual redetermination is scheduled for October 2023.

In October 2022, the Credit Facility was amended to replace the LIBOR rate with the secured overnight financing rate published by the Federal Reserve Bank of New York ("SOFR").

Outstanding borrowings under the Credit Facility bear interest at a floating rate elected by us equal to a base rate (which is a rate per annum equal to the highest of (a) the Prime Rate in effect on such day, (b) the Federal Funds Rate in effect on such day plus 0.50%, and (c) Adjusted Term SOFR for a one month tenor in effect on such day plus 1.00%) or Adjusted Term SOFR, in each case, plus the applicable margin.

As of December 31, 2022 and June 30, 2023, the applicable margin for the alternative base rate ranged from 1.50% to 2.50% and the Adjusted Term SOFR margin ranged from 2.50% to 3.50%, depending on the borrowings outstanding in relation to the borrowing base.

We are obligated to pay a quarterly commitment fee ranging from a 0.375% to 0.500% annualized rate on the unused portion of the borrowing base, depending on the amount of the borrowings outstanding in relation to the borrowing base.

Principal may be optionally repaid from time to time without premium or penalty, other than customary SOFR breakage, and is required to be paid (a) if the amount outstanding exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise, in some cases subject to a cure period, or (b) at the maturity date.

Our Credit Facility is secured by substantially all of our oil and natural gas production and assets.

Our credit agreement contains various affirmative, negative, and financial maintenance covenants.

These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates, and entering into certain derivative agreements, as well as require the maintenance of certain financial ratios.

The credit agreement contains two financial covenants:

total debt to EBITDAX of 3.5:1.0 or less and a current ratio of 1.0:1.0 or greater as defined in the credit agreement.

Distributions are not permitted if there is a default under the credit agreement (including the failure to satisfy one of the financial covenants), if the availability under the Credit Facility is less than 10% of the lenders' commitments, or if total debt to EBITDAX is greater than 3.0.

The lenders have the right to accelerate all of the indebtedness under the credit agreement upon the occurrence and during the continuance of any event of default, and the credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy, and change of control.

There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods.

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

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.

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

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.

Critical Accounting Policies and Related Estimates

As of June 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 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.

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