What changed in this filing

/stocks — the workspaceLOADING

Item 2. Management’s Discussion and Analysis

2022-05-03 compared with 2021-11-02 · 81 added, 171 removed, 261 unchanged (49% of the section changed)

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• 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;

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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, 2021, 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, 2022, 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 70,000 producing wells.

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Recent Developments

TLW Divestiture

In the third quarter of 2021, we closed on the divestiture of our wholly owned subsidiary, TLW Investments, L.L.C.

("TLW"), effective September 1, 2021 for total proceeds of $0.2 million.

TLW holds non-operating working interests and overriding royalty interests primarily located in Oklahoma and Texas.

Shelby Trough Development Update

Aethon has successfully turned to sales the initial two program wells and has commenced operations on four additional wells under the development agreement covering Angelina County.

In October 2021, Aethon spud the first three wells under the separate development agreement covering San Augustine County.

Aethon has successfully turned six wells to sales (four of which came online in April 2022) and has commenced operations on four additional wells under the development agreement covering Angelina County.

Aethon is currently drilling two wells and has another two wells awaiting completion operations under the separate development agreement covering San Augustine County.

Additionally, XTO Energy has resumed drilling three wells on our Shelby Trough acreage in San Augustine County that were originally spud in 2019.

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.

Recent drilling results have shown that advances in fracturing and other completion techniques can dramatically improve well performance in existing Austin Chalk fields.

One well has been drilled and turned to sales and five additional wells are currently being drilled under these agreements.

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 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.

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

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

Business Environment

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With widespread availability of vaccines, the U.S.

Centers for Disease Control and Prevention has revised its guidance, travel restrictions have started to lift, and businesses have reopened.

In the wake of a rise in COVID-19 cases resulting from new variants in our area, we have returned to remote work arrangements for all employees.

Employees are allowed the flexibility of going to the office when following health and safety guidelines established by the company.

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

We currently offer employees the option to work remotely or, subject to compliance with our health and safety guidelines, in the office.

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

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This, in turn, resulted in periods of significantly lower market prices for oil, natural gas, and natural gas liquids ("NGLs").

The price environment in 2020 caused many of our operators to reduce their drilling and completion activity on our acreage, which negatively impacts our production volumes.

Commodity prices improved in late 2020 and have fully recovered in 2021, reflecting expectations of rising demand as both COVID-19 vaccination rates and global economic activity increased, combined with ongoing crude oil production limits from members of the Organization of the Petroleum Exporting Countries and its broader partners.

However, the current price environment remains uncertain as responses to the COVID-19 pandemic continue to evolve.

Given the dynamic nature of these events, we cannot reasonably estimate the period of time that the COVID-19 pandemic and related market conditions will persist.

Commodity prices have subsequently recovered, reflecting expectations of rising demand as both COVID-19 vaccination rates and global economic activity increased, combined with ongoing crude oil production limits from members of the Organization of the Petroleum Exporting Countries and its broader partners.

In addition, Russia's military incursion into Ukraine and the subsequent sanctions imposed on Russia and other actions created significant market uncertainties about the potential for supply disruptions that further increased global commodity prices in the first quarter of 2022.

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

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 price environment in 2020, including the sharp decline in oil prices that began in March 2020, also caused us to determine that certain depletable units consisting of mature oil producing properties were impaired as of March 31, 2020.

Therefore, we recognized impairment of oil and natural gas properties of $51.0 million in the first quarter of 2020.

Additionally, the borrowing base under the Credit Facility takes into consideration the estimated loan value of our oil and natural gas properties.

Effective November 3, 2020, the borrowing base redetermination reduced the borrowing base from $430.0 million to $400.0 million.

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

The next borrowing base redetermination is scheduled for April 2022.

In a prolonged period of low commodity prices, we may be required to impair additional properties and the borrowing base under our Credit Facility could be further reduced.

The following table reflects commodity prices as of the last day 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) $ 100.53 $ 59.19

Henry Hub spot natural gas ($/MMBtu) 5.46 2.52

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 in Europe remain high amid supply uncertainties due to Russia's further invasion of Ukraine and the need to replenish Europe's natural gas inventories, which has kept Europe's demand for LNG elevated.

Net natural gas exports averaged 11.5 Bcf per day in the first quarter of 2022, an 18% increase from the 2021 average.

The EIA expects high levels of U.S.

LNG exports to continue, forecasting average exports of 12.4 Bcf per day for the rest of 2022 and 12.6 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.

While the rig count has recovered significantly from 2020 levels, this recovery has lagged the recovery in commodity prices as operators focus on greater capital discipline and efficiency.

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

Rotary Rig Count 1

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

Oil 421 372 324 183 188 624

First Quarter First Quarter

Natural gas 137 92

Other 1 — 1 3 2 2

Total 670 417

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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 779 513 307 872 639 382

First Quarter First Quarter

Midwest 317 401

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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, 2021 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, 2022 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, 2021, we have hedged 100% and 71% of our available oil and condensate hedge volumes for 2021 and 2022, respectively.

As of September 30, 2021, we have also hedged 84%, 72%, and 17% of our available natural gas hedge volumes for 2021, 2022, and 2023, respectively.

As of March 31, 2022, we have hedged 92% and 6% of our available oil and condensate hedge volumes for 2022 and 2023, respectively.

As of March 31, 2022, we have also hedged 72% and 16% of our available natural gas hedge volumes for 2022 and 2023, 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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Adjusted EBITDA and Distributable cash flow are supplemental non-GAAP financial measures used by our management and external users of our financial statements such as investors, research analysts, and others, to assess the financial performance of our assets and our ability to sustain distributions over the long term without regard to financing methods, capital structure, or historical cost basis.

We define Adjusted EBITDA as net income (loss) before interest expense, income taxes, and depreciation, depletion, and amortization adjusted for impairment of oil and natural gas properties, accretion of asset retirement obligations, unrealized gains and losses on commodity derivative instruments, non-cash equity-based compensation, and gains and losses on sales of assets.

We define Distributable cash flow as Adjusted EBITDA plus or minus amounts for certain non-cash operating activities, cash interest expense, distributions to preferred unitholders, and restructuring charges.

We define Adjusted EBITDA as net income (loss) before interest expense, income taxes, and depreciation, depletion, and amortization adjusted for impairment of oil and natural gas properties, if any, accretion of asset retirement obligations, unrealized gains and losses on commodity derivative instruments, non-cash equity-based compensation, and gains and losses on sales of assets, if any.

Adjusted EBITDA and Distributable cash flow should not be considered an alternative to, or more meaningful than, net income (loss), income (loss) from operations, cash flows from operating activities, or any other measure of financial performance presented in accordance with generally accepted accounting principles ("GAAP") in the United States as measures of our financial performance.

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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,

2021 2020 2021 2020

Three Months Ended March 31,

(in thousands)

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Depreciation, depletion, and amortization 10,917 15,632

Impairment of oil and natural gas properties — — — 51,031

Interest expense 1,209 1,210

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Unrealized (gain) loss on commodity derivative instruments 88,776 23,359

(Gain) loss on sale of assets, net (2,850) (24,045) (2,850) (24,045)

Adjusted EBITDA 98,756 59,984

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Preferred unit distributions (5,250) (5,250)

Restructuring charges 1

Distributable cash flow $ 92,635 $ 53,772

1 Restructuring charges include non-recurring costs associated with broad workforce reductions in the first quarter of 2020.

Results of Operations

Three Months Ended September 30, 2021 Compared to Three Months Ended September 30, 2020

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

2022 2021 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, 2021 increased compared to the quarter ended September 30, 2020.

The increase in total revenue from the corresponding period is due to an increase in oil and condensate sales, natural gas and NGL sales, and lease bonus and other income.

The overall increase in total revenue was partially offset by an increase in losses from our commodity derivative instruments.

Total revenue for the quarter ended March 31, 2022 decreased compared to the quarter ended March 31, 2021.

The decrease in total revenue from the corresponding period is primarily due to an increase in unrealized losses from our commodity derivative instruments and was partially offset by an increase 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, 2021 as compared to the corresponding period in 2020 due to higher realized commodity prices partially offset by lower production volumes.

Our mineral and royalty interest oil and condensate volumes accounted for 92% of total oil and condensate volumes for both quarters ended September 30, 2021 and 2020.

Oil and condensate sales increased for the quarter ended March 31, 2022 as compared to the corresponding period in 2021 primarily due to higher realized commodity prices while production volumes remained flat.

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, 2022 and 2021, respectively.

Natural gas and natural gas liquids sales.

Natural gas and NGL sales increased for the quarter ended September 30, 2021 as compared to the corresponding prior period.

The increase was primarily due to higher realized commodity prices between the comparative periods.

Mineral and royalty interest production accounted for 85% and 78% of our natural gas volumes for the quarters ended September 30, 2021 and 2020, respectively.

Natural gas and NGL sales increased for the quarter ended March 31, 2022 as compared to the corresponding prior period.

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

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.

Mineral and royalty interest production accounted for 89% and 82% of our natural gas volumes for the quarters ended March 31, 2022 and 2021, respectively.

Gain (loss) on commodity derivative instruments.

During the third quarter of 2021, we recognized an increase in losses from our commodity derivative instruments compared to the same period in 2020.

During the first quarter of 2022, we recognized an increase in losses from our commodity derivative instruments compared to the same period in 2021.

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, 2021, we recognized $34.1 million of realized losses and $43.4 million of unrealized losses from our oil and natural gas commodity contracts, compared to $21.3 million of realized gains and $42.4 million of unrealized losses in the same period in 2020.

The unrealized losses on our commodity contracts during the third quarter of 2021 were primarily driven by changes in the forward commodity price curves for natural gas.

The unrealized losses for the same period in 2020 were primarily driven by changes in the forward commodity price curves for oil and natural gas.

For the three months ended March 31, 2022, we recognized $31.2 million of realized losses and $88.8 million of unrealized losses from our oil and natural gas commodity contracts, compared to $4.5 million of realized losses and $23.4 million of unrealized losses in the same period in 2021.

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

The unrealized losses for the same period in 2021 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 third quarter of 2021 was higher than the same period in 2020.

Leasing activity in the Wolfcamp 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 third quarter of 2021, while a substantial portion of third quarter 2020 activity came from leasing activity in the Haynesville/Bossier play.

Lease bonus and other income for the first quarter of 2022 was higher than the same period in 2021.

Leasing activity in the Wolfcamp play made up the majority of lease bonus and other income for the first quarter of 2022, while a substantial portion of the first quarter 2021 activity came from leasing activity in the Austin Chalk 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 increased for the quarter ended September 30, 2021 as compared to the same period in 2020, primarily due to higher nonrecurring service-related expenses, including workovers.

Lease operating expense increased for the quarter ended March 31, 2022 as compared to the same period in 2021, primarily due to higher 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, 2021, production costs and ad valorem taxes increased as compared to the quarter ended September 30, 2020, primarily due to higher production taxes stemming from rising commodity prices partially offset by lower ad valorem tax estimates.

For the quarter ended March 31, 2022, production costs and ad valorem taxes increased as compared to the quarter ended March 31, 2021, primarily due to higher production taxes stemming from rising commodity prices partially offset by lower 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, 2021 and in the corresponding prior period in 2020.

Exploration expense was minimal for the quarter ended March 31, 2022 and in the corresponding prior period in 2021.

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, 2021 as compared to the same period in 2020, primarily due to a reduction in cost basis with a lower corresponding reduction in proved developed producing reserve quantities.

Depreciation, depletion, and amortization decreased for the quarter ended March 31, 2022 as compared to the same period in 2021, primarily due to 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.

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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, 2021, general and administrative expenses increased as compared to the same period in 2020, primarily due to a $1.7 million increase in cash compensation and a $1.4 million increase in equity compensation.

The increase in cash compensation was driven by projected outperformance relative to performance targets under our short-term cash incentive plan, and the increase in equity incentive compensation was due to higher costs recognized for performance-based incentive awards due to upward movements in our common unit price period over period.

Interest expense .

Interest expense was lower in the third quarter of 2021 relative to the corresponding period in 2020, due to lower average outstanding borrowings under our Credit Facility.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020

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

Nine Months Ended September 30,

2021 2020 Variance

(Dollars in thousands, except for realized prices)

Oil and condensate (MBbls) 2,610 2,980 (370) (12.4) %

Natural gas (MMcf) 1

46,053 51,922 (5,869) (11.3) %

Equivalents (MBoe) 10,286 11,634 (1,348) (11.6) %

Equivalents/day (MBoe) 37.7 42.5 (4.8) (11.3) %

Realized prices, without derivatives:

Oil and condensate ($/Bbl) $ 61.31 $ 37.53 $ 23.78 63.4 %

Natural gas ($/Mcf) 1

3.75 1.85 1.90 102.7 %

Equivalents ($/Boe) $ 32.33 $ 17.87 $ 14.46 80.9 %

Oil and condensate sales $ 160,028 $ 111,845 $ 48,183 43.1 %

Natural gas and natural gas liquids sales 1

172,537 96,060 76,477 79.6 %

Lease bonus and other income 12,195 7,669 4,526 59.0 %

Revenue from contracts with customers 344,760 215,574 129,186 59.9 %

Gain (loss) on commodity derivative instruments (164,923) 49,751 (214,674) NM 2

Total revenue $ 179,837 $ 265,325 $ (85,488) (32.2) %

Operating expenses:

Lease operating expense $ 9,804 $ 10,280 $ (476) (4.6) %

Production costs and ad valorem taxes 35,469 31,836 3,633 11.4 %

Exploration expense 1,080 28 1,052 3,757.1 %

Depreciation, depletion, and amortization 46,353 62,198 (15,845) (25.5) %

Impairment of oil and natural gas properties — 51,031 (51,031) NM 2

General and administrative 37,359 32,738 4,621 14.1 %

Other expense:

Interest expense 4,197 9,055 (4,858) (53.6) %

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.

2 Not meaningful.

Total revenue for the nine months ended September 30, 2021 decreased compared to the corresponding prior period.

The decrease in total revenue is due to a loss from our commodity derivative instruments for the nine months ended September 30, 2021 compared to a gain in the same period in 2020.

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

Oil and condensate sales.

Oil and condensate sales during the nine months ended September 30, 2021 increased compared to the corresponding prior period due to higher realized commodity prices partially offset by lower production volumes.

The decrease in oil and condensate production, primarily within the Permian Basin, was driven by divestitures of certain Permian Basin mineral and royalty properties in the third quarter of 2020.

Our mineral and royalty interest oil and condensate volumes accounted for 92% of total oil and condensate volumes for both the nine months ended September 30, 2021 and 2020.

Natural gas and natural gas liquids sales.

Natural gas and NGL sales during the nine months ended September 30, 2021 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 driven by decreases in working interest production volumes, primarily within the Haynesville/Bossier play.

Mineral and royalty interest production accounted for 83% and 76% of our natural gas volumes for the nine months ended September 30, 2021 and 2020, respectively.

Gain (loss) on commodity derivative instruments.

During the nine months ended September 30, 2021, we recognized a loss from our commodity derivative instruments compared to a gain for the same period in 2020.

In the nine months ended September 30, 2021, we recognized $56.0 million of realized losses and $108.9 million of unrealized losses from our oil and natural gas commodity contracts, compared to $66.8 million of realized gains and $17.0 million of unrealized losses in the same period in 2020.

The unrealized losses on our commodity contracts during the nine months ended September 30, 2021 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 2020 were primarily driven by changes in the forward commodity price curves for natural gas.

Lease bonus and other income.

Lease bonus and other income for the nine months ended September 30, 2021 was higher than the same period in 2020.

Leasing activity in the Austin Chalk and Wolfcamp plays and proceeds from surface use waivers on our mineral acreage supporting solar development in Mississippi and Texas made up the majority of lease bonus and other income for the nine months ended September 30, 2021, while a substantial portion of the activity in the corresponding prior period came from leasing activity in the Permian Basin, Green River Basin, and Bakken/Three Forks.

Operating and Other Expenses

Lease operating expense .

Lease operating expense decreased for the nine months ended September 30, 2021 as compared to the same period in 2020, primarily due to a decrease in variable costs as a result of lower production from our non-operating working interest properties.

Production costs and ad valorem taxes .

For the nine months ended September 30, 2021, production costs and ad valorem taxes increased as compared to the nine months ended September 30, 2020, primarily due to higher production taxes stemming from rising commodity prices partially offset by lower ad valorem tax estimates.

Exploration expense .

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

Exploration expense for the nine months ended September 30, 2020 was minimal.

Depreciation, depletion, and amortization .

Depreciation, depletion, and amortization decreased for the nine months ended September 30, 2021 as compared to the same period in 2020, primarily due to lower production volumes and 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.

Impairment of oil and natural gas properties .

Individual categories of oil and natural gas properties are assessed periodically to determine if the net book value for these properties has been impaired.

Management periodically conducts an in-depth evaluation of the cost of property acquisitions, successful exploratory wells, development activity, unproved leasehold, and mineral interests to identify impairments.

Impairments totaled $51.0 million for the nine months ended September 30, 2020, primarily due to declines in future expected realizable net cash flows as a result of lower commodity prices as of the measurement date of March 31, 2020.

There were no impairments for the nine months ended September 30, 2021.

General and administrative .

For the nine months ended September 30, 2021, general and administrative expenses increased as compared to the same period in 2020, primarily due to a $2.4 million increase in cash compensation and a $8.4 million increase in equity incentive compensation.

The increase in cash compensation was driven by projected outperformance relative to performance targets under our short-term cash incentive plan, and the increase in equity incentive compensation was due to higher costs recognized for performance-based incentive awards resulting from upward movements in our common unit price during the nine months ended September 30, 2021 compared to downward movements in our common unit price in the corresponding prior period.

The overall increase was partially offset by charges recognized for the nine months ended September 30, 2020 that did not recur.

This included $4.8 million of restructuring costs associated with workforce reductions in the first quarter of 2020 and a $1.1 million increase in allowance against an outstanding long-term receivable.

For the quarter ended March 31, 2022, general and administrative expenses increased slightly as compared to the same period in 2021, primarily due to a $1.1 million increase in equity compensation.

The increase in equity incentive compensation was due to higher costs recognized for performance-based incentive awards due to upward movements in our common unit price period over period.

Interest expense .

Interest expense was lower in the nine months ended September 30, 2021 than in the prior period primarily due to lower average outstanding borrowings under our Credit Facility.

The change in interest expense was minimal in the first quarter of 2022 relative to the corresponding period in 2021, due to lower average outstanding borrowings under our Credit Facility almost completely offset by higher interest rates.

Liquidity and Capital Resources

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

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, 2021, we had outstanding borrowings of $99.0 million under the Credit Facility.

As of March 31, 2022, we had outstanding borrowings of $69.0 million under the Credit Facility.

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:

Nine Months Ended September 30,

Three Months Ended March 31,

2022 2021 Change

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

Cash flows provided by operating activities decreased for the nine months ended September 30, 2021 as compared to the same period of 2020.

The decrease was primarily due to net cash paid on settlements of commodity derivative instruments in the nine months ended September 30, 2021 compared to net cash received in the same period of 2020.

The overall decrease was partially offset by increases in oil and condensate sales and natural gas and NGL sales due to higher realized commodity prices.

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

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

Investing Activities .

Net cash was used in investing activities in the nine months ended September 30, 2021 as compared to net cash provided by investing activities in the same period of 2020.

The change was primarily due to cash paid for acquisitions of oil and natural gas properties in the nine months ended September 30, 2021 compared to cash received from the sale of oil and natural gas properties in the same period of 2020.

Net cash used in investing activities in the three months ended March 31, 2022 decreased as compared to the same period of 2021.

The decrease was primarily due to cash received from the farmout of oil and natural gas properties in the three months ended March 31, 2022 compared to no cash received from the farmout of oil and natural gas properties in the same period of 2021.

Financing Activities .

Cash flows used in financing activities decreased for the nine months ended September 30, 2021 as compared to the same period of 2020.

The decrease was primarily due to lower net repayments under our Credit Facility in the nine months ended September 30, 2021 as compared to the corresponding prior period.

Cash flows used in financing activities increased for the three months ended March 31, 2022 as compared to the same period of 2021.

The increase was primarily due to higher distributions to unitholders and additional repayments on our line of credit in the three months ended March 31, 2022 as compared to the corresponding prior period.

Development Capital Expenditures

Our 2021 capital expenditure budget associated with our non-operated working interests is expected to be approximately $5.0 million, net of farmout reimbursements, of which $4.1 million has been invested in the nine months ended September 30, 2021.

The majority of this capital is anticipated to be spent for working interest participation on test wells in the Austin Chalk play and the remaining will be spent for workovers on existing wells in which we own a working interest.

Our 2022 capital expenditure budget associated with our non-operated working interests is expected to be approximately $4.5 million, net of farmout reimbursements, of which $0.1 million has been invested in the three months ended March 31, 2022.

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

2 unchanged sentences

Our Credit Facility terminates on November 1, 2024.

As of September 30, 2021, we had outstanding borrowings of $99.0 million at a weighted-average interest rate of 2.59%.

As of March 31, 2022, we had outstanding borrowings of $69.0 million at a weighted-average interest rate of 2.94%.

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.

5 unchanged sentences

Effective November 3, 2020, the borrowing base redetermination reduced the borrowing base from $430.0 million to $400.0 million.

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

The next semi-annual redetermination is scheduled for April 2022.

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

The next semi-annual redetermination is scheduled for October 2022.

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, 2020, the applicable margin for the alternative base rate ranged from 1.00% to 2.00% and the applicable margin for LIBOR ranged from 2.00% to 3.00%, depending on the borrowings outstanding in relation to the borrowing base.

As of September 30, 2021, the alternative base rate margin ranged from 1.50% to 2.50% and the LIBOR margin ranged from 2.50% to 3.50%.

As of December 31, 2021 and March 31, 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.

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, 2021, we were in compliance with all debt covenants.

On March 5, 2021, the U.K.

Financial Conduct Authority announced that it intends to stop persuading or compelling banks to submit LIBOR rates after December 31, 2021 for the 1-week and 2-month U.S.

dollar settings and after June 30, 2023 for the remaining U.S.

dollar settings.

Our Credit Facility includes provisions to determine a replacement rate for LIBOR if necessary during its term, based on the secured overnight financing rate published by the Federal Reserve Bank of New York ("SOFR").

As of March 31, 2022, we were in compliance with all debt covenants.

The 1-week and 2-month U.S.

dollar LIBOR settings ceased to be published after December 31, 2021 and the U.K.

Financial Conduct Authority intends to stop persuading or compelling banks to submit LIBOR rates for the remaining U.S.

dollar settings after June 30, 2023.

Our Credit Facility uses the 1-month LIBOR setting and includes provisions to determine a replacement rate for LIBOR if necessary during its term, based on the secured overnight financing rate published by the Federal Reserve Bank of New York (“SOFR”).

We currently do not expect the transition from LIBOR to have a material impact on us.

Contractual Obligations

As of September 30, 2021, there have been no material changes to our contractual obligations previously disclosed in our 2020 Annual Report on Form 10-K.

Off-Balance Sheet Arrangements

As of September 30, 2021, we did not have any material off-balance sheet arrangements.

As of March 31, 2022, there have been no material changes to our contractual obligations previously disclosed in our 2021 Annual Report on Form 10-K.

Critical Accounting Policies and Related Estimates

As of September 30, 2021, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our 2020 Annual Report on Form 10-K.

As of March 31, 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.

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