What changed in this filing

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Item 2. Management’s Discussion and Analysis

2023-05-02 compared with 2022-11-01 · 83 added, 172 removed, 244 unchanged (51% of the section changed)

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• our ability to execute our business strategies;

• the scope and duration of the COVID-19 pandemic and actions taken by governmental authorities and other parties in response to the pandemic;

• the conflict in Ukraine and actions taken, and may in the future be taken, against Russia or otherwise as a result;

• the volatility of realized oil and natural gas prices;

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• the overall supply and demand for oil and natural gas, regional supply and demand factors, delays, or interruptions of production;

• the availability of U.S.

liquefied natural gas ("LNG") export capacity and the level of demand for LNG exports;

• our ability to replace our oil and natural gas reserves;

• our ability to identify, complete, and integrate acquisitions;

• general economic, business, or industry conditions, including slowdowns, domestically and internationally and volatility in the securities, capital or credit markets;

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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, 2022, 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 March 31, 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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Shelby Trough Development Update

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

Aethon has turned four wells to sales and is currently drilling one well with another one waiting on completion under the separate development agreement covering San Augustine County.

Aethon’s completions are more intensive than those of prior operators in the area and result in higher initial flowback rates.

Additionally, XTO Energy has turned to sales the three wells on our Shelby Trough acreage in San Augustine county that were originally spud in 2019.

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

Aethon has successfully turned 4 wells to sales and has another nine wells awaiting completion operations under the separate development agreement covering San Augustine County.

Additionally, XTO Energy has resumed drilling on our Shelby Trough acreage in San Augustine County and has one well currently awaiting completion operations.

Austin Chalk Update

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

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 our 2021 three well test program in the Brookeland Field demonstrates that modern completion technology can greatly improve production rates and increase reserves when compared to the vintage, unstimulated wells in the Austin Chalk formation.

In addition to the test well program, eighteen new horizontal wells have been drilled on our acreage to test various portions of the field across a four-county area.

Although production results have varied on those wells, the play is becoming better delineated, with consistent well performance across certain areas.

Seven operators are actively engaged in redevelopment of the field, with four rigs currently running in the play.

To date, twenty-two wells with modern completions are now producing in the area, and an additional five are currently either being drilled or completed.

Eight operators are actively engaged in redevelopment of the field, with two rigs running continuously in the play.

To date, twenty-two wells with modern completions are now producing in the area, and an additional six are currently either being drilled or completed.

Business Environment

The information below is designed to give a broad overview of the oil and natural gas business environment as it affects us.

COVID-19 Pandemic and Market Conditions

The COVID-19 pandemic has adversely affected the global economy, disrupted global supply chains and created significant volatility in the financial markets.

With widespread availability of vaccines, the U.S.

Centers for Disease Control and Prevention has revised its guidance, most travel restrictions have been lifted, and many businesses have reopened.

We have transitioned to a hybrid work environment offering employees the ability to work remotely most days and, subject to compliance with our health and safety guidelines, in the office on other days.

We do not expect these arrangements to negatively impact our ability to maintain operations.

We continue to prioritize the health and safety of our workforce through frequent cleaning of common spaces, appropriate physical distancing measures, and other best practices as recommended by federal, state and local officials.

Commodity Prices and Demand

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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 and costless collar contracts.

Commodity prices have continued to recover in 2022, due to several factors, including higher demand for oil, natural gas, and natural gas liquids ("NGLs") from the lows of the pandemic, ongoing crude oil production limits from members of the Organization of the Petroleum Exporting Countries and its broader partners, and supply constraints due to Russia's military incursion into Ukraine and the subsequent sanctions imposed on Russia.

Rising inflation and actions taken by the Federal Reserve and other central banks to moderate inflation, including increasing interest rates, have reduced expectations for economic growth and contributed to volatility in commodity prices during the third quarter of 2022.

The current price environment remains uncertain as responses to the COVID-19 pandemic, rising inflation, and the conflict in Ukraine continue to evolve.

Commodity prices decreased from the prior period ended March 31, 2022, 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 as a result of reduced consumption due to the early emergence of warmer than expected weather conditions in the first two months of the quarter.

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, increases in LNG exports, and increased consumption in the electric power sector will raise prices in 2023.

Given the dynamic nature of these events, 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.

The following table reflects commodity prices as of the last day of each quarter presented:

The following table reflects commodity prices at the end of each quarter presented:

Benchmark Prices 1

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

First Quarter First Quarter

WTI spot oil price ($/Bbl) $ 75.68 $ 100.53

Henry Hub spot natural gas ($/MMBtu) 2.10 5.46

Natural Gas Exports

Rising levels of U.S.

LNG exports have been a growing source of demand and have positively impacted natural gas prices, particularly in the Gulf Coast region where the majority of our natural gas is produced.

LNG prices have been volatile in 2022 resulting from the uncertainty in the global natural gas markets leading up to and following Russia's full-scale invasion of Ukraine, as well as from weather-related fluctuations in natural gas demand.

Net natural gas exports averaged 10.8 Bcf per day in the nine months ended September 30, 2022, an 11% increase from the 2021 average.

On June 9, 2022, Freeport LNG shut down its Gulf Coast LNG export facility, which represents approximately 20% of the total U.S.

export capacity, due to an explosion at the facility.

In an August 23, 2022 statement, Freeport LNG indicated that it anticipates the export facility to be restored to 85% capacity by the end of November and full operations to resume by March 2023.

The EIA forecasts average exports of 11.8 Bcf per day for the rest of 2022 and 12.3 Bcf per day for 2023.

The EIA forecast reflects the assumption that global natural gas demand remains strong and that expected additional U.S.

LNG export capacity comes online.

As we are not the operator of record on any producing properties, drilling on our acreage is dependent upon the exploration and production companies that lease our acreage.

In addition to drilling plans that we seek from our operators, we also monitor rig counts in an effort to identify existing and future leasing and drilling activity on our acreage.

The following table shows the rig count as of the last day of each quarter presented:

The following table shows the rig count at the end of each quarter presented:

Rotary Rig Count 1

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

Oil 604 594 531 421 372 324

First Quarter First Quarter

Natural gas 160 137

Other 2 2 2 1 — 1

Total 755 670

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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 2022 at 3.5 Tcf, which is 6% lower than the previous five-year average.

The following table shows natural gas storage volumes by region as of the last day of each quarter presented:

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

East 756 461 268 779 513 307

The EIA estimates that natural gas inventories will conclude the injection season in October 2023 at 3.8 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:

First Quarter First Quarter

Midwest 421 317

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Total 1,830 1,416

Natural Gas Exports

The EIA expects an increase in U.S.

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

Net natural gas exports averaged 11.6 Bcf per day in the first quarter of 2023, a 10% increase from the 2022 average.

The EIA forecasts average exports of 12.2 Bcf per day for the rest of 2023 and 12.7 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.

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, 2022 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, 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 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, 2022, we have hedged 98% and 66% of our available oil and condensate hedge volumes for 2022 and 2023, respectively.

As of September 30, 2022, we have also hedged 72% and 65% of our available natural gas hedge volumes for 2022 and 2023, respectively.

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 March 31, 2023, we had hedged 67% and 22% of our available oil and condensate hedge volumes for 2023 and 2024, respectively.

As of March 31, 2023, we had also hedged 64% and 41% 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 September 30, Nine Months Ended September 30,

2022 2021 2022 2021

Three Months Ended March 31,

(in thousands)

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Unrealized (gain) loss on commodity derivative instruments (38,986) 88,776

(Gain) loss on sale of assets, net — (2,850) (17) (2,850)

Adjusted EBITDA 109,928 98,756

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Results of Operations

Three Months Ended September 30, 2022 Compared to Three Months Ended September 30, 2021

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

Three Months Ended September 30,

Three Months Ended March 31, 2023 Compared to Three Months Ended March 31, 2022

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

Three Months Ended March 31,

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 September 30, 2022 increased compared to the quarter ended September 30, 2021.

The increase in total revenue from the corresponding period is primarily due to an increase in sales of oil and condensate, natural gas, and NGLs in addition to unrealized gains from our commodity derivative instruments and an increase in our lease bonus and other income.

Total revenue for the quarter ended March 31, 2023 increased compared to the quarter ended March 31, 2022.

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

Oil and condensate sales.

Oil and condensate sales increased for the quarter ended September 30, 2022 as compared to the corresponding period in 2021 primarily due to higher realized commodity prices.

Our mineral and royalty interest oil and condensate volumes accounted for 94% and 92% of total oil and condensate volumes for quarters ended September 30, 2022 and 2021, respectively.

Oil and condensate sales decreased for the quarter ended March 31, 2023 as compared to the corresponding period in 2022 primarily due to lower realized commodity prices and production volumes.

Our mineral and royalty interest oil and condensate volumes accounted for 92% and 94% of total oil and condensate volumes for quarters ended March 31, 2023 and 2022, respectively.

Natural gas and natural gas liquids sales.

Natural gas and NGL sales increased for the quarter ended September 30, 2022 as compared to the corresponding prior period.

The increase was primarily due to higher realized commodity prices between the comparative periods and higher production volumes due to the timing of new development.

The increase in natural gas and NGL production was primarily driven by new activity in the Louisiana portion of the Haynesville/Bossier play trend.

The increase was partially offset by the natural decline in producing wells in the Shelby Trough outpacing new activity from the Aethon development program, which has not yet fully ramped up, in addition to lower working interest volumes in the area as a result of the farmout agreements put in place in 2017.

Mineral and royalty interest production accounted for 93% and 85% of our natural gas volumes for the quarters ended September 30, 2022 and 2021, respectively.

Natural gas and NGL sales decreased for the quarter ended March 31, 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.

Mineral and royalty interest production accounted for 94% and 89% of our natural gas volumes for the quarters ended March 31, 2023 and 2022, respectively.

Gain (loss) on commodity derivative instruments.

During the third quarter of 2022, we recognized a decrease in losses from our commodity derivative instruments compared to the same period in 2021.

During the first quarter of 2023, we recognized a gain from our commodity derivative instruments compared to a loss in 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, 2022, we recognized $68.9 million of realized losses and $64.1 million of unrealized gains from our oil and natural gas commodity contracts, compared to $34.1 million of realized losses and $43.4 million of unrealized losses in the same period in 2021.

The unrealized gains on our commodity contracts during the third quarter of 2022 and the unrealized losses for the same period in 2021 were primarily driven by changes in the forward commodity price curves for oil and natural gas during each period.

For the three months ended March 31, 2023, we recognized $13.3 million of realized gains and $39.0 million of unrealized gains from our oil and natural gas commodity contracts, compared to $31.2 million of realized losses and $88.8 million of unrealized losses in the same period in 2022.

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

The unrealized losses for the same period in 2022 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 third quarter of 2022 was higher than the same period in 2021.

Leasing activity in the Haynesville/Bossier and Wolfcamp plays made up the majority of lease bonus and other income for the third quarter of 2022, and a substantial portion for the third quarter of 2021.

Lease bonus and other income for the first quarter of 2023 was lower than the same period in 2022.

Leasing activity in the Haynesville/Bossier and Wolfcamp plays made up the majority of lease bonus and other income for the first quarter of 2023, while a substantial portion of the first quarter 2022 activity came from leasing activity in the Wolfcamp play.

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, 2022 as compared to the same period in 2021 due to a decrease in working interest production volumes in the period as a result of continued declines from our remaining working interest properties.

Due to the fixed costs from these remaining properties, our lease operating expense per BOE increased from the comparative period.

Lease operating expense decreased for the quarter ended March 31, 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 .

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

For the quarter ended September 30, 2022, production costs and ad valorem taxes increased as compared to the quarter ended September 30, 2021, primarily due to higher production taxes stemming from rising commodity prices and higher ad valorem tax estimates.

For the quarter ended March 31, 2023, production costs and ad valorem taxes decreased as compared to the quarter ended March 31, 2022, primarily due to lower production taxes stemming from falling commodity prices partially offset by higher 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 September 30, 2022 and in the corresponding prior period in 2021.

Exploration expense was minimal for the quarter ended March 31, 2023 and in the corresponding prior period in 2022.

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 September 30, 2022 as compared to the same period in 2021, primarily due to a reduction in cost basis from depreciation, depletion, and amortization recorded during the prior twelve months with an increase in proved developed producing reserve quantities.

Depreciation, depletion, and amortization increased for the quarter ended March 31, 2023 as compared to the same period in 2022, primarily due to increased production partially offset by a reduction in cost basis with a lower corresponding reduction in proved developed producing reserve quantities.

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

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, 2022, general and administrative expenses increased slightly as compared to the same period in 2021, primarily due to a $1.2 million increase in equity incentive compensation offset by a $0.4 million decrease in cash compensation.

The increase in equity incentive compensation was due to higher costs recognized for performance-based incentive awards resulting from larger upward movements in our common unit price during the three months ended September 30, 2022 compared to the corresponding prior period.

Interest expense .

Interest expense was higher in the third quarter of 2022 relative to the corresponding period in 2021, due to higher interest rates partially offset by lower average outstanding borrowings under our Credit Facility.

Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021

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

Nine Months Ended September 30,

2022 2021 Variance

(Dollars in thousands, except for realized prices)

Oil and condensate (MBbls) 2,574 2,610 (36) (1.4) %

Natural gas (MMcf) 1

42,648 46,053 (3,405) (7.4) %

Equivalents (MBoe) 9,682 10,286 (604) (5.9) %

Equivalents/day (MBoe) 35.5 37.7 (2.2) (5.8) %

Realized prices, without derivatives:

Oil and condensate ($/Bbl) $ 97.27 $ 61.31 $ 35.96 58.7 %

Natural gas ($/Mcf) 1

7.61 3.75 3.86 102.9 %

Equivalents ($/Boe) $ 59.39 $ 32.33 $ 27.06 83.7 %

Oil and condensate sales $ 250,367 $ 160,028 $ 90,339 56.5 %

Natural gas and natural gas liquids sales 1

324,691 172,537 152,154 88.2 %

Lease bonus and other income 10,262 12,195 (1,933) (15.9) %

Revenue from contracts with customers 585,320 344,760 240,560 69.8 %

Gain (loss) on commodity derivative instruments (152,095) (164,923) 12,828 7.8 %

Total revenue $ 433,225 $ 179,837 $ 253,388 140.9 %

Operating expenses:

Lease operating expense $ 9,256 $ 9,804 $ (548) (5.6) %

Production costs and ad valorem taxes 51,309 35,469 15,840 44.7 %

Exploration expense 192 1,080 (888) (82.2) %

Depreciation, depletion, and amortization 35,018 46,353 (11,335) (24.5) %

General and administrative 39,326 37,359 1,967 5.3 %

Other expense:

Interest expense 4,264 4,197 67 1.6 %

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, 2022 increased compared to the corresponding prior period.

The increase in total revenue is due to increased sales of oil and condensate, natural gas, and NGLs in addition to a decreased loss from our commodity derivative instruments for the nine months ended September 30, 2022 compared to the same period in 2021.

The overall increase in total revenue was partially offset by a decrease in lease bonus and other income for the nine months ended September 30, 2022 compared to the same period in 2021.

Oil and condensate sales.

Oil and condensate sales during the nine months ended September 30, 2022 increased compared to the corresponding prior period due to higher realized commodity prices.

Our mineral and royalty interest oil and condensate volumes accounted for 93% and 92% of total oil and condensate volumes for the nine month periods ended September 30, 2022 and 2021, respectively.

Natural gas and natural gas liquids sales.

Natural gas and NGL sales during the nine months ended September 30, 2022 increased compared to the corresponding prior period due to higher realized commodity prices partially offset by lower production volumes.

The decrease in natural gas and NGL production was primarily driven by the natural decline in producing wells in the Shelby Trough outpacing new activity from the Aethon development program, which has not yet fully ramped up, in addition to lower working interest volumes in the area as a result of the farmout agreements put in place in 2017.

The decrease was partially offset by new activity in the Louisiana portion of the Haynesville/Bossier play trend.

Mineral and royalty interest production accounted for 91% and 83% of our natural gas volumes for the nine months ended September 30, 2022 and 2021, respectively.

Gain (loss) on commodity derivative instruments.

During the nine months ended September 30, 2022, we recognized a decreased loss from our commodity derivative instruments compared to the same period in 2021.

In the nine months ended September 30, 2022, we recognized $162.6 million of realized losses and $10.5 million of unrealized gains from our oil and natural gas commodity contracts, compared to $56.0 million of realized losses and $108.9 million of unrealized losses in the same period in 2021.

The unrealized gains on our commodity contracts during the nine months ended September 30, 2022 and 2021 were primarily driven by changes in the forward commodity price curves for oil and natural gas during each period.

Lease bonus and other income.

Lease bonus and other income for the nine months ended September 30, 2022 was lower than the same period in 2021.

Leasing activity in the Haynesville/Bossier and Wolfcamp plays made up the majority of lease bonus and other income for the nine months ended September 30, 2022, and for the corresponding prior period.

Operating and Other Expenses

Lease operating expense .

Lease operating expense decreased for the nine months ended September 30, 2022 as compared to the same period in 2021 due to a decrease in working interest production volumes as a result of continued declines from our remaining working interest properties.

Due to the fixed costs from these remaining properties, our lease operating expense per BOE increased from the comparative period.

Production costs and ad valorem taxes .

For the nine months ended September 30, 2022, production costs and ad valorem taxes increased as compared to the nine months ended September 30, 2021, primarily due to higher production taxes stemming from rising commodity prices and higher ad valorem tax estimates.

Exploration expense .

Exploration expense for the nine months ended September 30, 2022 was minimal.

Exploration expense for the nine months ended September 30, 2021 primarily related to a dry hole drilled in the first quarter of 2021.

Depreciation, depletion, and amortization .

Depreciation, depletion, and amortization decreased for the nine months ended September 30, 2022 as compared to the same period in 2021, primarily due to a reduction in cost basis from depreciation, depletion, and amortization recorded during the prior twelve months with an increase in proved developed producing reserve quantities as well as lower natural gas production volumes.

General and administrative .

For the nine months ended September 30, 2022, general and administrative expenses increased as compared to the same period in 2021, primarily due to a $0.4 million increase in cash compensation and a $1.5 million increase in equity incentive compensation.

The increase in equity incentive compensation was due to higher costs recognized for performance-based incentive awards resulting from larger upward movements in our common unit price during the nine months ended September 30, 2022 compared to the corresponding prior period.

For the quarter ended March 31, 2023, general and administrative expenses decreased slightly as compared to the same period in 2022, primarily due to a $2.4 million decrease in equity compensation offset by a $1.7 million increase in cash compensation.

The decrease in equity incentive compensation was due to lower costs recognized for performance-based incentive awards due to downward movements in our common unit price period over period.

Interest expense .

Interest expense was higher in the nine months ended September 30, 2022 than in the prior period primarily due to higher interest rates partially offset by lower average outstanding borrowings under our Credit Facility.

Interest expense was lower in the first quarter of 2023 relative to the corresponding period in 2022, due to lower average outstanding borrowings under our Credit Facility and partially offset by higher interest rates.

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 September 30, 2022, we had outstanding borrowings of $60.0 million under the Credit Facility.

As of March 31, 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.

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

We intend to finance our 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, proceeds from any future issuances of equity and debt, and proceeds from asset sales.

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.

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

Nine Months Ended September 30,

Three Months Ended March 31,

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 nine months ended September 30, 2022 as compared to the same period of 2021.

The increase was primarily due to higher oil and condensate sales and natural gas and NGL sales due to higher realized commodity prices in the nine months ended September 30, 2022 compared to the same period of 2021.

The overall increase was partially offset by higher cash settlements paid on our commodity derivative instruments.

Cash flows provided by operating activities increased for the three months ended March 31, 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 nine months ended September 30, 2022 decreased as compared to the same period of 2021.

The decrease was primarily due to minimal cash paid for acquisitions of oil and natural gas properties in the nine months ended September 30, 2022 compared to the same period of 2021.

Net cash used in investing activities in the three months ended March 31, 2023 increased as compared to the same period of 2022.

The increase was primarily due to increased cash additions to oil and natural gas properties, net of farmout reimbursements in the three months ended March 31, 2023 as compared to the corresponding prior period.

Financing Activities .

Cash flows used in financing activities increased for the nine months ended September 30, 2022 as compared to the same period of 2021.

The increase was primarily due to higher distributions to unitholders.

Cash flows used in financing activities increased for the three months ended March 31, 2023 as compared to the same period of 2022.

The increase was primarily due to higher distributions to unitholders in the three months ended March 31, 2023 as compared to the corresponding prior period.

Development Capital Expenditures

Our 2022 capital expenditure budget associated with our non-operated working interests is expected to be approximately $2.0 million, net of farmout reimbursements, of which $0.5 million has been invested in the nine months ended September 30, 2022.

Our 2023 capital expenditure budget associated with our non-operated working interests is expected to be approximately $7.9 million, net of farmout reimbursements, of which $1.9 million has been invested in the three months ended March 31, 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.

Credit Facility

Pursuant to our $1.0 billion senior secured revolving credit agreement, as amended (the “Credit Facility”), the commitment of the lenders equals the least of the aggregate maximum credit amounts of the lenders, the then-effective borrowing base, which is determined based on the lenders’ estimated value of our oil and natural gas properties, and the aggregate elected commitment, as it may be adjusted from time to time.

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 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.

As of September 30, 2022, we had outstanding borrowings of $60.0 million at a weighted-average interest rate of 5.50%.

The borrowing base is redetermined semi-annually, typically in April and October of each year, by the administrative agent, taking into consideration the estimated loan value of our oil and natural gas properties consistent with the administrative agent’s normal lending criteria.

The administrative agent’s proposed redetermined borrowing base must be approved by all lenders to increase our existing borrowing base, and by two-thirds of the lenders to maintain or decrease our existing borrowing base.

In addition, 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 acquisition of oil and natural gas properties in excess of 10% of the value of the borrowing base immediately prior to such acquisition.

Our Credit Facility terminates on October 31, 2027.

As of March 31, 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 October 2021 and April 2022 borrowing base redeterminations reaffirmed the borrowing base at $400.0 million.

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

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.

No other significant terms were changed as part of the amendment.

Please see Item 5 of Part II of this quarterly report for a more detailed description of the amendment to the Credit Facility.

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

Outstanding borrowings under the Credit Facility bear interest at a floating rate elected by us equal to an alternative base rate (which is equal to the greatest of the Prime Rate, the Federal Funds effective rate plus 0.50%, or 1-month LIBOR plus 1.00%) or LIBOR, in each case, plus the applicable margin.

As of December 31, 2021 and September 30, 2022, the applicable margin for the alternative base rate ranged from 1.50% to 2.50% and the applicable margin for LIBOR ranged from 2.50% to 3.50%, depending on the borrowings outstanding in relation to the borrowing base.

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 March 31, 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.

8 unchanged sentences

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 September 30, 2022, we were in compliance with all debt covenants.

As of March 31, 2023, we were in compliance with all debt covenants.

Contractual Obligations

As of September 30, 2022, there have been no material changes to our contractual obligations previously disclosed in our 2021 Annual Report on Form 10-K.

As of March 31, 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 September 30, 2022, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our 2021 Annual Report on Form 10-K.

As of March 31, 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