What changed in this filing

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Item 7. Management’s Discussion and Analysis

2021-02-23 compared with 2020-02-25 · 130 added, 91 removed, 369 unchanged (37% of the section changed)

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As of December 31, 2020, our mineral and royalty interests were located in 41 states in the continental United States including all of the major onshore producing basins.

These non-cost-bearing interests include ownership in approximately 69,000 producing wells.

These non-cost-bearing interests include ownership in over 70,000 producing wells.

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

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Recent Developments

General and Administrative Expense Reductions

We have taken significant steps to reduce our general and administrative expenses, including broad workforce reductions and lower Board and executive compensation levels.

In light of this initiative and the constrained acquisition environment, Brock Morris, Senior Vice President, Engineering and Geology, and Holbrook Dorn, Senior Vice President, Business Development, have stepped down from their roles.

We expect to incur a one-time cash charge of approximately $5 million in the first quarter of 2020 associated with severance agreements for affected employees.

In 2019 we acquired mineral and royalty interests primarily in the Permian Basin and in East Texas for aggregate consideration of $43.1 million in cash and $0.9 million in our common units.

Additional information regarding acquisitions is contained in Note 4 – Oil and Natural Gas Properties to our consolidated financial statements included elsewhere in this Annual Report.

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.

Shelby Trough Update

As previously disclosed, drilling activity has slowed on our Shelby Trough acreage in East Texas, in part due to the current natural gas price environment.

XTO Energy Inc.

has informed us that it intends to postpone most of its drilling and completion activity until late 2020 or thereafter.

In addition, BPX Energy (“BPX”) has significantly reduced current development in the Shelby Trough and has released over 100,000 gross acres.

Much of this area has been delineated with seismic data and through BPX’s drilling to date with successful wells in both the Haynesville and Bossier shales.

While a protracted slowdown of activity in the Shelby Trough would reduce production and, in turn, cash available for distribution, we currently expect to place that acreage with another operator or operators in 2020.

End of the Subordination Period

The subordination period under the partnership agreement ended on the first business day after we earned and paid an aggregate amount of at least $1.35 (the annualized minimum quarterly distribution applicable for quarterly periods ending March 31, 2019 and thereafter) multiplied by the total number of outstanding common and subordinated units for a period of four consecutive, non-overlapping quarters ending on or after March 31, 2019, and there were no outstanding arrearages on the common units.

This test was met upon the payment of the distribution for the first quarter of 2019.

Accordingly, each outstanding subordinated unit converted into one common unit on May 24, 2019 and the priority right of the common unitholders ceased to exist.

Common Unit Repurchase Program

On November 5, 2018, the Board authorized the repurchase of up to $75.0 million in common units.

The repurchase program authorizes us to make repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legal requirements, available liquidity, and other appropriate factors.

All or a portion of any repurchases may be made under a Rule 10b5-1 plan, which would permit common units to be repurchased when we might otherwise be precluded from doing so under applicable laws.

The repurchase program does not obligate us to acquire any particular amount of common units and may be modified or suspended at any time and could be terminated prior to completion.

We will periodically report the number of common units repurchased.

In 2019, we repurchased a total of 136,665 common units for an aggregate cost of $2.2 million.

As of December 31, 2019, we have repurchased $4.2 million in common units under the repurchase program since inception.

The repurchase program is funded from cash on hand or availability under the Credit Facility.

Any repurchased units are canceled.

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.

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.

Business Environment

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

COVID-19 Pandemic and Market Conditions

The COVID-19 pandemic 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.

Commodity Prices and Demand

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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, 2019, the WTI oil spot price reached a low of $46.31 per Bbl on January 2, 2019 but increased to a high of $66.24 per Bbl on April 23, 2019.

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, 2019, Henry Hub spot natural gas prices ranged from a high of $4.25 per MMBtu on March 4, 2019 to a low of $1.75 per MMBtu on December 27, 2019.

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.

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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.

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.

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 2020, at almost 2.0 Tcf, or 14% higher than the five-year average.

The EIA expects inventories will reach almost 4.1 Tcf at the end of October 2020, which would be the highest end-of-October inventory level on record.

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

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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, and non-cash equity-based compensation.

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, and distributions to noncontrolling interests and preferred unitholders.

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.

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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Year Ended December 31,

2019 2018 2017

(in thousands)

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Depreciation, depletion, and amortization 82,018 109,584

Impairment of oil and natural gas properties 51,031 —

Interest expense 10,408 21,435

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Unrealized (gain) loss on commodity derivative instruments 35,238 32,817

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

Adjusted EBITDA 281,335 399,470

Adjustments to Distributable cash flow:

Adjustments to reconcile to Distributable cash flow:

Change in deferred revenue (391) 42

Cash interest expense (9,364) (20,394)

(Gain) loss on sale of assets, net — (3) (931)

Estimated replacement capital expenditures 1

(2,750) (11,500) (13,500)

Cash paid to noncontrolling interests — (211) (120)

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

Restructuring charges 4,815 —

Distributable cash flow $ 255,395 $ 355,368

1 The Board established a replacement capital expenditure estimate of $15.0 million for the period of April 1, 2016 to March 31, 2017, $13.0 million for the period of April 1, 2017 to March 31, 2018, and $11.0 million for the period of April 1, 2018 to March 31, 2019.

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.

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Equivalents (MBoe) 15,219 17,716 (2,497) (14.1) %

Equivalents/day (MBoe) 41.6 48.5 (6.9) (14.2) %

Realized prices, without derivatives:

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Revenue from contracts with customers 296,640 492,776 (196,136) (39.8) %

Gain (loss) on commodity derivative instruments (4,955) 14,831 (19,786) (133.4) %

Gain (loss) on commodity derivative instruments 46,111 (4,955) 51,066 NM 2

Total revenue $ 342,751 $ 487,821 $ (145,070) (29.7) %

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Depreciation, depletion, and amortization 82,018 109,584 (27,566) (25.2) %

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

General and administrative 42,983 63,353 (20,370) (32.2) %

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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.

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 decreased oil and condensate sales and natural gas and NGL sales as a result of lower realized commodity prices, lower lease bonus and other income, and a loss on commodity derivative instruments in 2019 compared to a gain in 2018.

The overall decrease was partially offset by an increase in natural gas production.

Production for 2019 averaged 48.5 MBoe per day, an increase of 2.2 MBoe per day compared to 2018.

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.

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 Bakken/Three Forks and Eagle Ford plays.

mineral and royalty interest oil and condensate volumes accounted for 92% and 90% of total oil and condensate volumes for the years ended December 31, 2019 and 2018, respectively.

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.

Natural gas and natural gas liquids sales.

Natural gas and NGL sales decreased for the year ended December 31, 2019 as compared to the year ended December 31, 2018 due to lower realized commodity prices, partially offset by increased production volumes.

The increase in natural gas production was primarily driven by higher production in the Haynesville/Bossier play.

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.

Mineral and royalty interest production accounted for 76% and 69% of our natural gas volumes for the years ended December 31, 2020 and 2019, respectively.

Gain (loss) on commodity derivative instruments.

During 2019, we recognized a loss from our commodity derivative instruments compared to a gain in 2018.

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

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 2019, we recognized $27.9 million of realized gains and $32.8 million of unrealized losses from our commodity derivatives, compared to $38.2 million of realized losses and $53.1 million of unrealized gains in 2018.

The realized gains from our commodity derivatives during 2019 were primarily related to cash settlements received on natural gas derivative instruments, while the realized losses during 2018 were primarily related to cash settlements paid on oil derivative instruments.

The unrealized losses on our commodity contracts in 2019 and the unrealized gains in 2018 were primarily driven by changes in the forward commodity price curves for oil during each period.

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.

Lease bonus and other income .

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Lease bonus and other income was lower for the year ended December 31, 2020, as compared to the same period in 2019.

Leasing activity in the Bakken/Three Forks, Haynesville/Bossier, Permian, 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.

Leasing activity in the Bakken/Three Forks, Haynesville/Bossier, Permian, and Austin Chalk plays made up the majority of lease bonus and other income in 2018.

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 2019 as compared to 2018, primarily due to decreased repairs and maintenance and other nonrecurring expenses on wells in which we own a non-operating working interest.

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.

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, 2019, production and ad valorem taxes decreased as compared to the year ended December 31, 2018, as a result of lower commodity prices, partially offset by increased natural gas production volumes.

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.

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 2019 primarily consisted of costs incurred to acquire third-party 3-D seismic information related to our mineral and royalty interests.

Exploration expense for 2018 primarily related to the costs incurred on the PepperJack B#1 well.

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, 2019 as compared to 2018, primarily due to the impact of lower depletion rates partially offset by higher production volumes.

Lower depletion rates in 2019 were primarily driven by increases in estimated proved developed producing reserve quantities in the Haynesville/Bossier formation and the Permian Basin.

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.

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 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.

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, 2019, general and administrative expenses decreased compared to 2018, primarily due to lower costs associated with our incentive compensation plans.

This decrease was driven by higher costs recognized in 2018 on incentive compensation awarded in connection with our initial public offering in 2015, higher costs recognized in 2018 due to outperformance relative to performance targets, and lower costs recognized in 2019 on performance-based incentive awards due to the decrease in our common unit price period over period.

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.

Other Expense

Interest expense.

For the year ended December 31, 2019, interest expense increased compared to 2018, primarily due to higher average outstanding borrowings partially offset by lower interest rates under our Credit Facility.

The increase in average outstanding borrowings was primarily due to the funding of acquisitions in 2019 and 2018.

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.

Liquidity and Capital Resources

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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 $15.0 million for the period of April 1, 2016 to March 31, 2017, $13.0 million for the period of April 1, 2017 to March 31, 2018, and $11.0 million for the period of April 1, 2018 to March 31, 2019.

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.

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Cash flows provided by operating activities $ 281,809 $ 412,720 $ (130,911)

Cash flows used in investing activities (48,623) (163,804) 115,181

Cash flows provided by (used in) investing activities 151,246 (48,623) 199,869

Cash flows provided by (used in) financing activities (439,378) (361,392) (77,986)

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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.

The increase in cash flows from operations was primarily due to a net increase in cash flows from changes in operating assets and liabilities for 2019 compared to a net decrease for 2018

and net cash received on settlement of commodity derivative instruments for 2019 compared to net cash paid for 2018.

The overall increase in cash flows from operations was partially offset by decreased oil and condensate sales and natural gas and NGL sales driven by lower realized commodity prices and decreased lease bonus and other income.

Cash provided by operating activities for 2020 decreased as compared to 2019.

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.

Investing Activities .

Net cash used in investing activities decreased in 2019 as compared to 2018.

The decrease was primarily due to reduced oil and natural gas property acquisitions and expenditures, net of proceeds from our farmout agreements.

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.

Financing Activities .

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

The increase was primarily due to increased distributions to common and subordinated unitholders and net repayments under our Credit Facility in 2019 compared with net borrowing in 2018.

We also sold no common units under our at-the-market offering program during 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.

Development Capital Expenditures

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Our 2021 capital expenditure budget associated with our non-operated working interests is expected to be approximately $5 million, net of farmout reimbursements.

The majority of this capital will be spent for workovers on existing wells in which we own a working interest.

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.

During 2018, we spent approximately $36.3 million associated with our non-operated working interests in certain Haynesville/Bossier wells in the Shelby Trough area of East Texas, net of farmout reimbursements, related to completions in wells which were spud prior to the farmouts.

In the PepperJack prospect area, we spent approximately $11.9 million during 2018 to drill and log two wells targeting the Lower Wilcox formation.

We spent an additional $0.5 million related to the completion costs for the PepperJack A#1 well in the fourth quarter of 2018.

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.

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

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

In addition, we and the lenders (at the election of two-thirds of the lenders) each have discretion to have the borrowing base redetermined once between scheduled redeterminations.

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

Effective May 4, 2018, the borrowing base redetermination increased the borrowing base from $550.0 million to $600.0 million.

Effective October 31, 2018, the borrowing base was further increased to $675.0 million and remained at that level until the most recent redetermination, effective October 23, 2019, which reduced the borrowing base to $650.0 million.

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.

The next semi-annual redetermination is scheduled for April 2021.

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.

Prior to October 31, 2018, the applicable margin ranged from 1.00% to 2.00% in the case of the alternative base rate and from 2.00% to 3.00% in the case of LIBOR, depending on the borrowings outstanding in relation to the borrowing base.

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 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%.

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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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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In some circumstances, it may be uncertain whether proved commercial reserves have been discovered when drilling has been completed.

Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to

justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is ongoing.

Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is ongoing.

Other exploratory costs, including annual delay rentals and geological and geophysical costs, are expensed when incurred.

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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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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 no impairment of proved oil and natural gas properties for the years ended December 31, 2019 and 2018.

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The expected sales volumes and prices for these properties are estimated and recorded within the Accounts receivable line item in the accompanying consolidated balance sheets.

The difference between our estimates and the actual amounts received for oil and natural gas sales is recorded in the

month that payment is received from the third party.

The difference between our estimates and the actual amounts received for oil and natural gas sales is recorded in the month that payment is received from the third party.

For the years ended December 31, 2020 and 2019, revenue recognized in the reporting periods related to performance obligations satisfied in prior reporting periods was immaterial.

3 unchanged sentences

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

We do not enter into derivative instruments for speculative purposes.

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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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