What changed in this filing

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Item 7. Management’s Discussion and Analysis

2022-02-22 compared with 2021-02-23 · 132 added, 155 removed, 344 unchanged (45% of the section changed)

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

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

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 December 31, 2021, our mineral and royalty interests were located in 41 states in the continental United States including all of the major onshore producing basins.

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Recent Developments

In July 2020, we closed two separate divestitures of certain mineral and royalty properties in the Permian Basin for total proceeds, after final closing adjustments, of $150.6 million.

The proceeds were used to reduce outstanding borrowings under our Credit Facility.

One of these transactions, effective May 1, 2020, involved the sale of our mineral and royalty interests in specific tracts in Midland County, Texas for net proceeds of approximately $54.5 million.

The other transaction, effective July 1, 2020, involved the sale of an undivided interest across parts of our Delaware Basin and Midland Basin positions for net proceeds of approximately $96.1 million.

We estimate the production associated with the properties sold, in total, to be approximately 1,800 Boe per day at the time of the sale.

COVID-19 Pandemic and Commodity Prices

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

In addition, the pandemic has resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement in many communities.

To protect the health and well-being of our workforce in the wake of COVID-19, we have implemented remote work arrangements for all employees.

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

We will continue to prioritize the health and safety of our workforce when employees return to the office through frequent cleaning of common spaces, appropriate social distancing measures, and other best practices as recommended by state and local officials.

The impact of the COVID-19 pandemic has negatively affected the oil and natural gas business environment, primarily by causing a reduction in commercial activity and travel worldwide thereby lowering energy demand.

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

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 current price environment has caused many of our operators to reduce their drilling and completion activity on our acreage, and caused some of our operators to temporarily shut-in production from existing wells, both of which negatively impact our production volumes.

While we believe most of the shut-in production has been brought back on-line, drilling and completion activity remains depressed relative to pre-pandemic levels.

The current price environment, 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, which takes into consideration the estimated loan value of our oil and natural gas properties, was reduced from $650.0 million to $460.0 million, effective May 1, 2020.

Effective July 21, 2020, in connection with the closing of our two asset sales in the Permian Basin, the borrowing base was further reduced to $430.0 million.

Effective November 3, 2020, the most recent borrowing base redetermination reduced the borrowing base to $400.0 million.

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.

In light of the challenging business environment and uncertainty caused by the pandemic, the board of directors of our general partner (the "Board") also approved a reduction in the quarterly distribution for the first quarter of 2020 to increase the amount of retained free cash flow for debt reduction and balance sheet protection.

The Board approved increases to the quarterly distribution for the second and fourth quarters of 2020, but the distribution remains below 2019 levels.

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.

In the second quarter of 2021, we closed an acquisition of mineral and royalty acreage in the northern Midland Basin for

total consideration of $20.8 million.

The purchase price consisted of $10.0 million in cash and $10.8 million in common units

of the Partnership.

The cash consideration was funded with borrowings under the Credit Facility and funds from operating

The assets acquired consisted of $4.9 million of proved oil and natural gas properties, $15.6 million of unproved oil

and natural gas properties, and $0.3 million of net working capital.

Shelby Trough Update

On May 4, 2020, we entered into a development agreement with affiliates of Aethon Energy ("Aethon") with respect to our undeveloped Shelby Trough Haynesville and Bossier shale acreage in Angelina County, Texas.

The agreement provides for minimum well commitments by Aethon in exchange for reduced royalty rates and exclusive access to our mineral and leasehold acreage in the contract area.

The agreement calls for a minimum of four wells to be drilled in the initial program year, which began in the third quarter of 2020, increasing to a minimum of 15 wells per year beginning with the third program year.

Aethon has successfully spud the initial two program wells under the development agreement.

On June 10, 2020, we entered into a new incentive agreement with XTO Energy Inc.

("XTO") with respect to certain drilled but uncompleted wells ("DUCs") in our Shelby Trough acreage in San Augustine County, Texas.

The agreement allows for royalty relief on 13 existing DUCs if XTO completes and turns the wells to sales by March 31, 2021, and complements the recent development agreement with Aethon covering our Shelby Trough acreage in Angelina County towards our goal of reviving volume growth from the area.

As of January 18, 2021, XTO has turned all 13 DUCs to sales.

In Angelina County, Texas, two wells are currently producing under our development agreement with Aethon, and another eight wells are being drilled or completed.

Aethon is currently drilling three wells under the separate development agreement covering San Augustine County, Texas.

Austin Chalk Update

We are currently working with several operators to test and develop 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 from the Austin Chalk formation.

In February of 2021, we entered into an agreement with a large, publicly traded independent operator by which the operator will undertake a program to drill, test, and complete wells in the Austin Chalk formation on certain of our acreage in East Texas.

If successful, the operator has the option to expand its drilling program over a significant acreage position owned and controlled by us.

We are also working with existing operators across our East Texas Austin Chalk position to encourage new development utilizing current completion techniques.

We entered into agreements with multiple operators to drill wells using advanced fracturing and completion techniques in the areas of the Austin Chalk in East Texas where we have significant acreage positions.

Five wells have been drilled and turned to sales, and another two wells are in various stages of drilling or completion under these agreements.

Early results from

these wells, while showing some variability, demonstrate that higher-intensity completions can significantly improve well performance relative to prior generation completion technology and the performance of unstimulated wells.

Business Environment

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COVID-19 Pandemic and Market Conditions

The COVID-19 pandemic and related economic repercussions have resulted in a significant reduction in demand for and prices of oil, natural gas and NGLs.

In the first quarter of 2020 and into the second quarter of 2020, oil prices fell sharply, due in part to significantly decreased demand as a result of the COVID-19 pandemic and the announcement by Saudi Arabia of a significant increase in its maximum oil production capacity as well as the announcement by Russia that previously agreed upon oil production cuts between members of the Organization of the Petroleum Exporting Countries and its broader partners (“OPEC+”) would expire on April 1, 2020, and the ensuing expiration thereof.

Agreed-upon production cuts by OPEC+ along

with declining U.S.

production have helped to correct the supply and demand imbalance;

however, these reductions are not expected to be enough in the near-term to offset the significant inventory build caused by demand destruction from the COVID-19 pandemic.

These market conditions have resulted in a decline in drilling activity as operators revise their capital budgets downward and adjust their operations in response to lower commodity prices.

Crude oil and natural gas spot prices in early 2021 and contract future prices for the full year 2021 have improved significantly from levels seen in the second quarter of 2020;

however, drilling activity remains depressed relative to levels experienced in 2018 and 2019.

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.

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, travel restrictions have started to lift, and businesses have reopened.

In the wake of a rise in COVID-19 cases resulting from new variants, we have maintained 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.

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

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

The EIA forecasts that WTI oil prices will average approximately $49.70 per Bbl in 2021 and $49.81 per Bbl in 2022.

During the year ended December 31, 2020, the WTI oil spot price reached a high of $63.27 per Bbl on January 6, 2020, but decreased to a low of $8.91 per Bbl on April 21, 2020.

This excludes the period in April 2020 when WTI briefly traded in negative territory.

The EIA forecasts that the Henry Hub spot natural gas price will average $3.01 per MMBtu for 2021 and $3.27 per MMBtu for 2022.

During the year ended December 31, 2020, Henry Hub spot natural gas prices ranged from a high of $3.14 per MMBtu on October 26, 2020 to a low of $1.33 per MMBtu on September 21, 2020.

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.

During the year ended December 31, 2021, the WTI oil spot prices ranged from a high of $85.64 per Bbl on October 26, 2021 to a low of $47.47 per Bbl on January 4, 2021.

During the year ended December 31, 2021, Henry Hub spot natural gas prices ranged from a high of $23.86 per MMBtu on February 17, 2021 to a low of $2.43 per MMBtu on April 5, 2021.

This, in turn, resulted in

periods of significantly lower market prices for oil, natural gas, and natural gas liquids.

Commodity prices improved in late 2020 and 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.

The improvement in commodity prices caused many of our operators to resume their drilling and completion activity on our acreage.

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.

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 at the end of each quarter presented:

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From November to March, storage levels typically decline as utility companies draw natural gas from storage to meet increased heating demand due to colder weather.

order to maintain sufficient storage levels for increased seasonal demand, a portion of natural gas production during the summer months must be used for storage injection.

In order to maintain sufficient storage levels for increased seasonal demand, a portion of natural gas production during the summer months must be used for storage injection.

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 forecasts that inventories will conclude the withdrawal season, which is the end of March 2021, at almost 1.6 Tcf, or 12% lower than the five-year average.

The EIA expects inventories will reach almost 3.6 Tcf at the end of October 2021, which would be 5% lower than the five-year average.

The EIA forecasts that inventories will conclude the withdrawal season, which is the end of March 2022, at 1.8 Tcf, or 8% higher than the five-year average.

The EIA expects inventories will rise to 3.7 Tcf at the end of October 2022, which would be within 1% of the five-year average.

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

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Total 3,194 3,170 2,558 1,763

Natural Gas Exports

Rising levels of U.S.

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

The EIA expects natural gas exports will reach record highs in 2022 and continue to grow in 2023 due to a combination of both rising LNG exports and increases in pipeline exports to Mexico.

Net natural gas exports averaged 10.7 Bcf per day in 2021 and the EIA forecasts that they will increase to 13.4 Bcf per day in 2022 and 14.3 Bcf per day in 2023.

How We Evaluate Our Operations

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Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end user markets.

The rise in LNG exports from the United States has increased demand for domestic natural gas production and had a positive impact on natural gas prices.

The EIA expects high levels of U.S.

LNG exports to continue into 2022, averaging 16% above 2021 levels.

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

LNG export capacity comes online.

We enter into derivative instruments to partially mitigate the impact of commodity price volatility on our cash generated from operations.

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The impact of these derivative instruments could affect the amount of revenue we ultimately realize.

Our open derivative contracts consist of fixed-price swap contracts and costless collar contracts.

Our open derivative contracts consist of fixed-price swap contracts.

Under fixed-price swap contracts, a counterparty is required to make a payment to us if the settlement price is less than the swap strike price.

Conversely, we are required to make a payment to the counterparty if the settlement price is greater than the swap strike price.

Our costless collar contracts contain a fixed floor price and a fixed ceiling price.

If the market price exceeds the fixed ceiling price, we pay the difference between the fixed ceiling price and the market settlement price.

If the market price is below the fixed floor price, we receive the difference between the market settlement price and the fixed floor price.

If the market price is between the fixed floor and fixed ceiling price, no payments are due from either party.

If we have multiple contracts outstanding with a single counterparty, unless restricted by our agreement, we will net settle the contract payments.

We may employ contractual arrangements other than fixed-price swap contracts and costless collar contracts in the future to mitigate the impact of price fluctuations.

We may employ contractual arrangements other than fixed-price swap contracts in the future to mitigate the impact of price fluctuations.

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

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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 December 31, 2020, we had hedged 98% of our available oil and condensate hedge volumes and 80% of our available natural gas hedge volumes for 2021.

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 for the following 12 to 30 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 December 31, 2021, we had hedged 63% of our available oil and condensate hedge volumes for 2022 and 65% and 14% of our available natural gas hedge volumes for 2022 and 2023, respectively.

We do not enter into derivative instruments for speculative purposes.

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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, estimated replacement capital expenditures during the subordination period, cash interest expense, distributions to noncontrolling interests and preferred unitholders, and restructuring charges.

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

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 U.S.

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Cash interest expense (4,059) (9,364)

Estimated replacement capital expenditures 1

Preferred unit distributions (21,000) (21,000)

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Distributable cash flow $ 267,401 $ 255,395

1 The Board established a replacement capital expenditure estimate of $11.0 million for the period of April 1, 2018 to March 31, 2019.

Due to the expiration of the subordination period, we do not intend to establish a replacement capital expenditure estimate for periods subsequent to March 31, 2019.

Results of Operations

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Depreciation, depletion, and amortization 61,019 82,018 (20,999) (25.6) %

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

Impairment of oil and natural gas properties — 51,031 (51,031) (100.0) %

General and administrative 48,746 42,983 5,763 13.4 %

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2 Not meaningful.

Total revenue for the year ended December 31, 2020 decreased compared to the year ended December 31, 2019.

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 as a result of lower realized commodity prices and lower production volumes, and a decrease in lease bonus and other income.

The overall decrease was partially offset by a gain on commodity derivative instruments in 2020 compared to a loss in 2019.

Total revenue for the year ended December 31, 2021 increased compared to the year ended December 31, 2020.

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

The overall increase was partially offset by a loss on commodity derivative instruments in 2021 compared to a gain in 2020.

Oil and condensate sales.

Oil and condensate sales for the year ended December 31, 2020 were lower than the corresponding period in 2019 due to decreased production volumes and lower realized commodity prices.

The decrease in oil and condensate production was primarily driven by lower production in the Permian Basin and the Bakken/Three Forks.

Our mineral and royalty interest oil and condensate volumes accounted for 92% of total oil and condensate volumes for each of the years ended December 31, 2020 and 2019.

Oil and condensate sales for the year ended December 31, 2021 were higher than the corresponding period in 2020 due to higher realized commodity prices partially offset by lower production volumes.

The decrease in oil and condensate production was primarily due to reduced production volumes from the Permian Basin and Eagle Ford.

The decrease in Permian Basin production was driven by divestitures of certain Permian Basin mineral and royalty properties in the third quarter of 2020 and the decrease in Eagle Ford production was driven by normal production declines with less new development activity.

Our mineral and royalty interest oil and condensate volumes accounted for 93% and 92% of total oil and condensate volumes for the years ended December 31, 2021 and 2020, respectively.

Natural gas and natural gas liquids sales.

Natural gas and NGL sales decreased for the year ended December 31, 2020 as compared to the year ended December 31, 2019 due to lower realized commodity prices and lower production volumes.

The decrease in natural gas production was driven by lower volumes in the Haynesville/Bossier play primarily due to reduced drilling activity and shut-in production volumes associated with the completion of certain DUCs on our Shelby Trough acreage.

Natural gas and NGL sales increased for the year ended December 31, 2021 as compared to the year ended December 31, 2020 due to higher realized commodity prices 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 84% and 76% of our natural gas volumes for the years ended December 31, 2021 and 2020, respectively.

Gain (loss) on commodity derivative instruments.

During 2020, we recognized a gain from our commodity derivative instruments compared to a loss in 2019.

During 2021, we recognized a loss from our commodity derivative instruments compared to a gain in 2020.

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.

During 2020, we recognized $81.3 million of realized gains and $35.2 million of unrealized losses from our commodity derivatives, compared to $27.9 million of realized gains and $32.8 million of unrealized losses in 2019.

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

The unrealized losses on our commodity contracts in 2019 were primarily driven by changes in the forward commodity price curves for oil, partially offset by changes in the forward commodity price curves for natural gas.

During 2021, we recognized $112.9 million of realized losses and $33.5 million of unrealized losses from our commodity derivatives, compared to $81.3 million of realized gains and $35.2 million of unrealized losses in 2020.

The unrealized losses on our commodity contracts in 2021 and 2020 were both 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 income 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 was lower for the year ended December 31, 2020, as compared to the same period in 2019.

Lease bonus and other income was higher for the year ended December 31, 2021, as compared to the same period in 2020.

Leasing activity in the Austin Chalk and Wolfcamp plays and proceeds from surface use waiver on our mineral acreage supporting solar development in Mississippi, Texas, and California made up the majority of lease bonus and other income in 2021.

Leasing activity in the Permian Basin, Haynesville/Bossier, Green River Basin, and Bakken/Three Forks plays, as well as certain surface leases in Polk County, Texas made up the majority of lease bonus and other income in 2020.

Leasing activity in the Bakken/Three Forks, Haynesville/Bossier, Permian Basin, and Woodbine plays, as well as proceeds from the settlement of a dispute with one of our operators, made up the majority of lease bonus and other income in 2019.

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 in 2020 as compared to 2019, primarily due to lower nonrecurring service-related expenses, including workovers, as well as a decrease in variable costs as a result of lower production from our non-operated working interest properties.

Lease operating expense decreased in 2021 as compared to 2020, primarily due to a decrease in variable costs as a result of lower production from our non-operated working interest properties.

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 year ended December 31, 2020, production and ad valorem taxes decreased as compared to the year ended December 31, 2019, as a result of lower commodity prices and lower production volumes.

For the year ended December 31, 2021, production and ad valorem taxes increased as compared to the year ended December 31, 2020, as a result of higher 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 for 2021 primarily related to a dry hole drilled in the first quarter of 2021.

Exploration expense for 2020 was minimal.

Exploration expense for 2019 primarily consisted of costs incurred to acquire 3-D seismic information related to our mineral and royalty interests from a third-party service provider.

Depreciation, depletion, and amortization.

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Estimates of proved developed producing reserves are a major component of the calculation of depletion.

We adjust our depletion rates semi-annually based upon the 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 expense decreased for the year ended December 31, 2020 as compared to 2019, primarily due to lower production volumes and a reduction in cost basis with lower corresponding reduction in proved developed producing reserve quantities.

The reduction in cost basis is primarily due to oil and natural gas property divestitures, continued depreciation, depletion, and amortization, and oil and natural gas property impairments.

We adjust our depletion rates semi-annually based upon the 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 expense decreased for the year ended December 31, 2021 as compared to 2020, primarily due to lower production volumes and a reduction in cost basis with lower

corresponding reduction in proved developed producing reserve quantities.

The reduction in cost basis is primarily due to oil and natural gas property divestitures in the third quarter of 2020, and continued depreciation, depletion, and amortization.

Impairment of oil and natural gas properties.

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

Impairments totaled $51.0 million for the year ended December 31, 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 2019.

There was no impairment for December 31, 2021.

There was $51.0 million in impairment for 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.

General and administrative.

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

For the year ended December 31, 2020, general and administrative expenses decreased compared to 2019, primarily due to a $8.9 million decrease in cash compensation and a $16.8 decrease in equity-based compensation.

The decrease in cash compensation is primarily resulting from the broad workforce reductions in the first quarter of 2020.

The decrease in equity-based compensation is due in part to these same workforce reductions but also due to downward cost revisions recognized in 2020 for performance-based incentive awards due to the decrease in our common unit price period over period.

The overall decrease was partially offset by $4.8 million of restructuring charges in the first quarter of 2020 associated with the workforce reductions.

For the year ended December 31, 2021, general and administrative expenses increased compared to 2020, primarily due to a $3.5 million increase in cash compensation and a $8.2 million increase in equity-based compensation.

The increase in cash compensation was driven by projected outperformance relative to performance targets under our short-term cash incentive plan.

The increase in equity-based compensation was due to higher costs recognized for performance-based incentive awards resulting from upward movements in our common unit price during 2021 compared to downward movements in our common unit price in 2020.

The overall increase was partially offset by charges recognized in 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.

Other Expense

Interest expense.

For the year ended December 31, 2020, interest expense decreased compared to 2019, primarily due to lower average outstanding borrowings and lower interest rates under our Credit Facility.

For the year ended December 31, 2021, interest expense decreased compared to 2020, primarily due to lower average outstanding borrowings partially offset by higher interest rates under our Credit Facility.

Liquidity and Capital Resources

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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, and proceeds from any future issuances of equity and debt.

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.

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.

Replacement capital expenditures are expenditures necessary to replace our existing oil and natural gas reserves or otherwise maintain our asset base over the long-term.

The Board established a replacement capital expenditure estimate of $11.0 million for the period of April 1, 2018 to March 31, 2019.

Due to the expiration of the subordination period, we do not intend to establish a replacement capital expenditure estimate for periods subsequent to March 31, 2019.

Year Ended December 31, 2021 Compared to Year Ended December 31, 2020

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Cash provided by operating activities for 2021 decreased as compared to 2020.

The decrease was primarily due to decreased oil and condensate sales and natural gas and NGL sales driven by lower realized commodity prices and lower production.

The overall decrease was partially offset by higher net cash received on settlement of commodity derivative instruments.

The decrease was primarily due to net cash paid on settlements of commodity derivative instruments in 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.

Investing Activities .

Net cash was provided by investing activities for 2020 as compared to net cash used in investing activities for 2019.

The change was primarily due to increased proceeds from the sale of oil and natural gas properties as well as a decrease in oil and natural gas property acquisitions and additions in 2020 as compared with 2019.

Net cash was used in investing activities for 2021 as compared to net cash being provided by investing activities for 2020.

The change was primarily due to cash paid for acquisitions of oil and natural gas properties in 2021 compared to proceeds from the sale of oil and natural gas properties in 2020.

Financing Activities .

Cash flows used in financing activities for 2020 increased as compared to 2019.

The increase was primarily due to increased net repayments under our Credit Facility in 2020 compared with 2019.

The overall increase was partially offset by lower distributions to common unitholders and decreased repurchases of common units.

Cash flows used in financing activities for 2021 decreased as compared to 2020.

The decrease was primarily due to lower net repayments under our Credit Facility in 2021 compared with 2020.

The overall decrease was partially offset by higher distributions paid to common unitholders.

Development Capital Expenditures

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Our 2022 capital expenditure budget associated with our non-operated working interests is expected to be approximately $4.5 million, net of farmout reimbursements.

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.

During 2020, we spent approximately $0.6 million associated with our non-operated working interests, net of farmout reimbursements.

During 2019, we spent approximately $4.3 million associated with our non-operated working interests, net of farmout reimbursements.

The majority of this capital was spent for workovers on existing wells in which we own a working interest or for acquiring new leasehold acreage for subsequent farmout in the Haynesville/Bossier play.

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

We spent approximately $4.2 million and $0.6 million associated with our non-operated working interests, net of farmout reimbursements during 2021 and 2020, respectively.

During 2021 we closed an acquisition of mineral and royalty acreage in the northern Midland Basin for total consideration of $20.8 million.

The purchase price consisted of $10.0 million in cash and $10.8 million in common units.

The assets acquired consisted of $4.9 million of proved oil and natural gas properties, $15.6 million of unproved oil and natural gas properties, and $0.3 million of net working capital.

We had no acquisition activity during 2020.

During 2019 we spent approximately $43.1 million and issued common units valued at $0.9 million related to acquisitions of mineral and royalty interests, which also included proved oil and natural gas properties.

During 2018 we spent approximately $127.3 million and issued common units valued at $22.6 million related to acquisitions of mineral and royalty interests, which also included proved oil and natural gas properties.

See Note 4 – Oil and Natural Gas Properties to the consolidated financial statements included elsewhere in this Annual Report for additional information.

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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.

Effective October 23, 2019, the borrowing base redetermination reduced the borrowing base to $650.0 million.

Effective May 1, 2020, the borrowing base was further reduced to $460.0 million.

Effective July 21, 2020, in connection with the closing of two asset sales in the Permian Basin, the borrowing base was further reduced to $430.0 million.

Effective November 3, 2020, the most recent borrowing base redetermination reduced the borrowing base to $400.0 million.

Effective November 3, 2020, the borrowing base redetermination reduced the borrowing base 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.

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.

Effective October 31, 2018, the applicable margin for the alternative base rate was reduced to between 0.75% and 1.75% and the applicable margin for LIBOR was reduced to between

1.75% and 2.75%.

Effective November 3, 2020, the LIBOR margin was increased to between 2.00% and 3.00% and the alternative base rate margin was increased to between 1.00% and 2.00%.

As of December 31, 2020 the applicable margin for the alternative base rate ranged from 1.00% and 2.00% and the applicable margin for LIBOR ranged from 2.00% and 3.00% depending on the borrowings outstanding in relation to the borrowing base.

As of December 31, 2021, the alternative base rate margin ranged from 1.50% to 2.50% and the LIBOR margin ranged from 2.50% to 3.50%.

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.

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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) or during any time that our borrowing base is lower than the loans outstanding under 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.

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As of December 31, 2021, we were in compliance with all debt covenants.

On July 27, 2017, the U.K.

Financial Conduct Authority announced that it intends to stop persuading or compelling banks to submit LIBOR rates after 2021.

Our Credit Facility includes provisions to determine a replacement rate for LIBOR if necessary during its term, which require that we and our lenders agree upon a replacement rate based on the then-prevailing market convention for similar agreements.

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”).

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

However, if clear market standards and replacement methodologies have not developed as of the time LIBOR becomes unavailable, we may have difficulty reaching agreement on acceptable replacement rates under our Credit Facility.

In the event that we do not reach agreement on an acceptable replacement rate for LIBOR, outstanding borrowings under the Credit Facility would revert to a floating rate equal to the alternative base rate (which, as of the time that LIBOR becomes unavailable, is equal to the greater of the Prime Rate and the Federal Funds effective rate plus 0.50%) plus the applicable margin for the alternative base rate which ranges between 1.00% and 2.00%.

If we are unable to negotiate replacement rates on favorable terms, it could have a material adverse effect on our financial condition, results of operations, and cash distributions to unitholders.

Contractual Obligations

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Total $ 92,464 $ 1,933 $ 90,531 $ — $ —

Off-Balance Sheet Arrangements

At December 31, 2020, we did not have any material off-balance sheet arrangements.

Critical Accounting Policies and Related Estimates

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Certain of our accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used.

The following discussions of critical accounting estimates, including any related discussion of contingencies, address all important accounting areas where the nature of

accounting estimates or assumptions could be material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change.

The following discussions of critical accounting estimates, including any related discussion of contingencies, address all important accounting areas where the nature of accounting estimates or assumptions could be material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change.

We have provided expanded discussion of our more significant accounting estimates below.

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Our reserve estimates are determined by an independent petroleum engineering firm.

Other items subject to significant estimates and assumptions include the carrying amount of oil and natural gas properties, valuation of commodity derivative financial instruments, valuation of future asset retirement obligations (“ARO”), determination of revenue accruals, and the determination of the fair value of equity-based awards.

Other items subject to significant estimates and assumptions include the carrying amount of oil and natural gas properties, valuation of commodity derivative financial instruments, determination of revenue accruals, and the determination of the fair value of equity-based awards.

We evaluate estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment.

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Oil and natural gas properties are grouped in accordance with the Extractive Industries – Oil and Gas Topic of the Financial Accounting Standards Board Accounting Standards Codification.

The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field, which we also refer to as a depletable unit.

The basis for grouping is a reasonable aggregation of properties with a common geographic location, which we also refer to as a depletable unit.

As exploration and development work progresses and the reserves associated with our oil and natural gas properties become proved, capitalized costs attributed to the properties are charged as an operating expense through DD&A.

DD&A of producing oil and natural gas properties is recorded based on the units-of-production method.

Capitalized development costs are amortized on the basis of proved developed reserves while leasehold acquisition costs and the costs to acquire proved properties

are amortized on the basis of all proved reserves, both developed and undeveloped.

Capitalized development costs are amortized on the basis of proved developed reserves while leasehold acquisition costs and the costs to acquire proved properties are amortized on the basis of all proved reserves, both developed and undeveloped.

Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

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This evaluation is performed on a depletable unit basis.

We compare the undiscounted projected future cash flows expected in connection with a depletable unit to its unamortized carrying amount to determine recoverability.

We compare the undiscounted projected future cash flows expected in connection with a depletable unit to its unamortized carrying amount to

determine recoverability.

When the carrying amount of a depletable unit exceeds its estimated undiscounted future cash flows, the carrying amount is written down to its fair value, which is measured as the present value of the projected future cash flows of such properties.

The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, operating costs, future capital expenditures, and a risk-adjusted discount rate.

There was a collapse in oil prices during the first quarter of 2020 due to geopolitical events that increased supply at the same time demand weakened due to the impact of the COVID-19 pandemic.

We determined these events and circumstances indicated a possible decline in the recoverability of the carrying value of certain proved properties and recoverability testing determined that certain depletable units consisting of mature oil producing properties were impaired as of March 31,2020.

We recognized $51.0 million of impairment of proved oil and natural gas properties for the year ended December 31, 2020.

There was a collapse in oil prices during the first quarter of 2020 due to geopolitical events that increased supply at the

same time demand weakened due to the impact of the COVID-19 pandemic.

The Partnership determined these events and

circumstances indicated a possible decline in the recoverability of the carrying value of certain proved properties and

recoverability testing determined that certain depletable units consisting of mature oil producing properties were impaired.

There was no impairment of proved oil and natural gas properties for the years ended December 31, 2021 and 2019.

We recognized $51.0 million of impairment of proved oil and natural gas properties for the year ended December 31, 2020.

Unproved properties are also assessed for impairment periodically on a depletable unit basis when facts and circumstances indicate that the carrying value may not be recoverable, at which point an impairment loss is recognized to the extent the carrying value exceeds the estimated recoverable value.

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Applying this discount results in an approximate 2% reduction of estimated proved reserve volumes as compared to the undiscounted pricing scenario used in our December 31, 2021 reserve report prepared by NSAI.

Asset Retirement Obligations

Under various contracts, permits, and regulations, we have legal obligations to restore the land at the end of operations at certain properties where we own non-operated working interests.

Estimating the future restoration costs necessary for this accounting calculation is difficult.

Most of these restoration obligations are many years, or decades, in the future and the contracts and regulations often have vague descriptions of what practices and criteria must be met when the event actually occurs.

Asset-restoration technologies and costs, regulatory and other compliance considerations, expenditure timing, and other inputs into the valuation of the obligation, including discount and inflation rates, are also subject to change.

Fair values of legal obligations to retire and remove long-lived assets are recorded when the obligation is incurred and becomes determinable.

When the liability is initially recorded, we capitalize this cost by increasing the carrying amount of the related property.

Over time, the liability is accreted for the change in its present value, and the capitalized cost in oil and natural gas properties is depleted based on units-of-production consistent with the related asset.

Revenues from Contracts with Customers

Accounting Standards Codification ("ASC") 606, Revenue from Contracts with Customers , requires us to identify the distinct promised goods and services within a contract which represent separate performance obligations and determine the transaction price to allocate to the performance obligations identified.

We adopted ASC 606 using the modified retrospective method, which was applied to all existing contracts for which all (or substantially all) of the revenue had not been recognized under legacy revenue guidance as of the date of adoption, January 1, 2018.

Oil and natural gas sales

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Given that we do not recognize lease bonus or other income until a lease agreement has been executed, at which point its performance obligation has been satisfied, and payment is received, we do not record revenue for unsatisfied or partially unsatisfied performance obligations as of the end of the reporting period.

Overall, there were no material changes in the timing of the satisfaction of our performance obligations or the allocation of the transaction price to our performance obligations in applying the guidance in ASC 606 as compared to legacy GAAP.

Prior-period performance obligations

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Our ongoing operations expose us to changes in the market price for oil and natural gas.

To mitigate the given price risk associated with its operations, we use commodity derivative financial instruments.

To mitigate the given price risk associated with our operations, we use commodity derivative financial instruments.

From time to time, such instruments may include variable-to-fixed price swaps, costless collars, fixed-price contracts, and other contractual arrangements.

enter into derivative instruments for speculative purposes.

We do not enter into derivative instruments for speculative purposes.

The impact of these derivative instruments could affect the amount of revenue we ultimately record.

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Please read Note 9 – Incentive Compensation within the consolidated financial statements included elsewhere in this Annual Report for additional information.

New and Revised Financial Accounting Standards

The effects of new accounting pronouncements are discussed in Note 2 – Summary of Significant Accounting Policies within the consolidated financial statements included elsewhere in this Annual Report.

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-K

Item 7. Management’s Discussion and Analysis