What changed in this filing

/stocks — the workspaceLOADING

Item 2. Management’s Discussion and Analysis

2020-11-03 compared with 2020-08-04 · 102 added, 107 removed, 360 unchanged (37% of the section changed)

40 unchanged sentences

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.

As of June 30, 2020, our mineral and royalty interests were located in 41 states in the continental United States, including all of the major onshore producing basins.

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

As of September 30, 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.

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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 to a private buyer for gross proceeds of approximately $55 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 to Pegasus Resources, LLC, a portfolio company of EnCap Investments, for gross proceeds of approximately $100 million.

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

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 $95.7 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

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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, significantly reducing prices of oil, natural gas, and natural gas liquids ("NGLs").

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 some of our operators' wells to become uneconomic, which has resulted, and may continue to result, in suspension of production from those wells or a significant reduction in or no royalty revenues from existing production.

Some operators may also attempt to shut in producing wells and avoid lease termination or payment of shut-in royalties by claiming force majeure, if provided for in the applicable lease.

Because these shut-ins have happened so recently, and no operator has, to our knowledge claimed force majeure, we have not been able to quantify their impact on our future revenues.

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.

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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 an increase in the quarterly distribution for the second quarter of 2020 but the distribution remains below 2019 levels.

The Board approved an increase in the quarterly distribution for the second quarter of 2020 and maintained that distribution for the third quarter of 2020, but the distribution remains below 2019 levels.

Shelby Trough Update

1 unchanged sentence

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 begins in the third quarter of 2020, increasing to a minimum of 15 wells per year beginning with the third program year.

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.

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

2 unchanged sentences

recent development agreement with Aethon covering our Shelby Trough acreage in Angelina County towards our goal of reviving volume growth from the area.

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 purchased 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.

We made no repurchases under this program for the six months ended June 30, 2020.

As of June 30, 2020, we have repurchased $4.2 million in common units under the repurchase program since inception.

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

Any repurchased units are canceled.

Business Environment

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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 and dramatically, 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.

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 in the first half of 2020.

We expect these market conditions to result in a continued decline in drilling activity as operators revise their capital budgets downward and adjust their operations, including shutting in producing wells, in response to lower commodity prices.

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.

While oil prices have remained depressed, both natural gas spot prices and contract future prices for the fourth quarter of 2020 and for the full year 2021 have improved significantly from levels seen in the second quarter of 2020.

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.

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To manage the variability in cash flows associated with the projected sale of our oil and natural gas production, we use various derivative instruments, which have recently consisted of fixed-price swap contracts and costless collar contracts.

The following table reflects commodity prices as of each date presented:

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

Benchmark Prices 1

June 30, 2020 March 31, 2020 June 30, 2019 March 31, 2019

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

WTI spot oil price ($/Bbl) $ 40.05 $ 39.27 $ 20.51 $ 54.09 $ 58.20 $ 60.19

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

The following table shows the rig count as of each date presented:

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

Rotary Rig Count 1

June 30, 2020 March 31, 2020 June 30, 2019 March 31, 2019

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

Oil 183 188 624 713 793 816

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The portion of production used for storage varies from year to year depending on the demand from the previous winter and the demand for electricity used for cooling during the summer months.

The EIA estimates that natural gas inventories will conclude the injection season on October 31, 2020 at 4.0 Tcf, or 8% higher than the previous five-year average.

The following table shows natural gas storage volumes by region as of each date presented:

June 30, 2020 March 31, 2020 June 30, 2019 March 31, 2019

The EIA estimates that natural gas inventories concluded the injection season on October 31, 2020 at 4.0 Tcf, or 8% higher than the previous five-year average.

However, because expected natural gas production will be lower this winter than last winter, the EIA forecasts inventory draws will outpace the five-year average during the heating season and end March 2021 at 1.7 Tcf, which would be 6% lower than the five-year average.

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

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

East 872 639 382 826 526 210

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The substantial majority of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control.

NYMEX light sweet crude oil, commonly referred to as West Texas Intermediate ("WTI"), is the prevailing domestic oil pricing index.

NYMEX light sweet crude oil, commonly referred to as West Texas

Intermediate ("WTI"), is the prevailing domestic oil pricing index.

The majority of our oil production is priced at the prevailing market price with the final realized price affected by both quality and location differentials.

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

Our open oil and natural gas derivative contracts as of June 30, 2020 are detailed in Note 4 - Commodity Derivative Financial Instruments to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

Our open oil and natural gas derivative contracts as of September 30, 2020 are detailed in Note 4 - Commodity Derivative Financial Instruments to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

Pursuant to the terms of our Credit Facility, we are allowed to hedge certain percentages of expected future monthly production volumes equal to the lesser of (i) internally forecasted production and (ii) the average of reported production for the most recent three months.

We are allowed to hedge up to 90% of such volumes for the first 24 months, 70% for months 25 through 36, and 50% for months 37 through 48.

As of June 30, 2020, we have hedged all of our available oil and condensate hedge volumes and 83% of our available natural gas hedge volumes for 2020.

As of June 30, 2020, we have also hedged 70% of our available oil and condensate hedge volumes and 57% of our available natural gas hedge volumes for 2021.

As of September 30, 2020, we have hedged all of our available oil and condensate hedge volumes and 81% of our available natural gas hedge volumes for 2020.

As of September 30, 2020, we have also hedged 69% of our available oil and condensate hedge volumes and 73% 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.

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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, distributions to preferred unitholders, and restructuring charges.

Gains and losses on sales of assets were previously included in Adjusted EBITDA and excluded from Distributable cash flows.

We believe this change to remove gains and losses on sales of assets from the definition of Adjusted EBITDA more closely conforms with peer company practice.

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

2 unchanged sentences

The following table presents a reconciliation of net income (loss), the most directly comparable GAAP financial measure, to Adjusted EBITDA and Distributable cash flow for the periods indicated:

Three Months Ended June 30, Six Months Ended June 30,

Three Months Ended September 30, Nine Months Ended September 30,

2020 2019 2020 2019

9 unchanged sentences

Unrealized (gain) loss on commodity derivative instruments 42,374 (10,644) 17,043 6,026

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

Adjusted EBITDA 65,505 96,162 209,004 299,430

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Results of Operations

Three Months Ended June 30, 2020 Compared to Three Months Ended June 30, 2019

Three Months Ended September 30, 2020 Compared to Three Months Ended September 30, 2019

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

Three Months Ended June 30,

Three Months Ended September 30,

2020 2019 Variance

31 unchanged sentences

2 Not meaningful.

Total revenue for the quarter ended June 30, 2020 decreased compared to the quarter ended June 30, 2019.

The decrease in total revenue from the corresponding period is due to a loss on our commodity derivative instruments in the second quarter of 2020 compared to a gain in the second quarter of 2019, 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.

Total revenue for the quarter ended September 30, 2020 decreased compared to the quarter ended September 30, 2019.

The decrease in total revenue from the corresponding period is due to a loss on our commodity derivative instruments in the third quarter of 2020 compared to a gain in the third quarter of 2019, 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.

Oil and condensate sales.

Oil and condensate sales decreased for the quarter ended June 30, 2020 as compared to the corresponding period in 2019 due to lower realized commodity prices and lower production volumes.

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

Our mineral and royalty interest oil and condensate volumes accounted for 93% of total oil and condensate volumes for both quarters ended June 30, 2020 and 2019.

Oil and condensate sales decreased for the quarter ended September 30, 2020 as compared to the corresponding period in 2019 due to lower realized commodity prices and lower production volumes.

The decrease in oil and condensate production was primarily driven by production volume decreases in the Permian Basin.

Our mineral and royalty

interest oil and condensate volumes accounted for 92% of total oil and condensate volumes for both quarters ended September 30, 2020 and 2019.

Natural gas and natural gas liquids sales.

Natural gas and NGL sales decreased for the quarter ended June 30, 2020 as compared to the corresponding prior period due to lower realized commodity prices and lower production volumes.

The decrease in natural gas and NGL production was primarily driven by production volume decreases in the Haynesville/Bossier play.

Mineral and royalty interest production accounted for 76% and 70% of our natural gas volumes for the quarters ended June 30, 2020 and 2019, respectively.

Natural gas and NGL sales decreased for the quarter ended September 30, 2020 as compared to the corresponding prior period due to lower realized commodity prices and lower production volumes.

The decrease in natural gas and NGL production was driven by production volume decreases 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 78% and 71% of our natural gas volumes for the quarters ended September 30, 2020 and 2019, respectively.

Gain (loss) on commodity derivative instruments.

During the second quarter of 2020, we recognized a loss from our commodity derivative instruments compared to a gain in the same period in 2019.

During the third quarter of 2020, we recognized a loss from our commodity derivative instruments compared to a gain in the same period 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.

For the three months ended June 30, 2020, we recognized $36.6 million of realized gains and $55.7 million of unrealized losses from our oil and natural gas commodity contracts, compared to $2.9 million of realized gains and $26.3 million of unrealized gains in the same period in 2019.

The unrealized losses on our commodity contracts during the second quarter of 2020 was primarily driven by changes in the forward commodity price curve for oil.

The unrealized gains in the same period in 2019 were primarily driven by changes in the forward commodity price curve for natural gas.

For the three months ended September 30, 2020, we recognized $21.3 million of realized gains and $42.4 million of unrealized losses from our oil and natural gas commodity contracts, compared to $13.6 million of realized gains and $10.6 million of unrealized gains in the same period in 2019.

The unrealized losses on our commodity contracts during the third quarter of 2020 was primarily driven by changes in the forward commodity price curves for oil and natural gas.

The unrealized gains in the same period in 2019 were primarily driven by changes in the forward commodity price curve for oil.

Lease bonus and other income.

1 unchanged sentence

Lease bonus revenue can vary substantively between periods because it is derived from individual transactions with operators, some of which may be significant.

Lease bonus and other income for the second quarter of 2020 was lower than the same period in 2019.

Leasing activity in the Permian Basin made up the majority of lease bonus revenue in the second quarter of 2020, while a substantial portion of second quarter 2019 activity came from the Permian Basin and the Wilcox.

Lease bonus and other income for the third quarter of 2020 was lower than the same period in 2019.

Leasing activity in the Haynesville/Bossier play as well as certain surface leases in Polk County, Texas made up the majority of lease bonus revenue in the third quarter of 2020, while a substantial portion of third quarter 2019 activity came from the Permian Basin and the Bakken/Three Forks trend.

Operating Expenses

1 unchanged sentence

Lease operating expense includes recurring expenses associated with our non-operated working interests necessary to produce hydrocarbons from our oil and natural gas wells, as well as certain nonrecurring expenses, such as well repairs.

Lease operating expense decreased for the quarter ended June 30, 2020 as compared to the same period in 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-operating working interest properties.

Lease operating expense decreased for the quarter ended September 30, 2020 as compared to the same period in 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-operating working interest properties.

Production costs and ad valorem taxes .

4 unchanged sentences

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

For the quarter ended June 30, 2020, production costs and ad valorem taxes decreased as compared to the quarter ended June 30, 2019, primarily as a result of lower commodity prices and lower production volumes.

For the quarter ended September 30, 2020, production costs and ad valorem taxes decreased as compared to the quarter ended September 30, 2019, primarily 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 was minimal for each of the three months ended June 30, 2020 and 2019.

Exploration expense was minimal for each of the three months ended September 30, 2020 and 2019.

Depreciation, depletion, and amortization .

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We adjust our depletion rates semi-annually based upon mid-year and year-end reserve reports, except when circumstances indicate that there has been a significant change in reserves or costs.

Depreciation, depletion, and amortization decreased for the quarter ended June 30, 2020 as compared to the same period in 2019, primarily due to lower production volumes and a reduction in cost basis with a lower corresponding reduction in proved developed producing reserve quantities.

Depreciation, depletion, and amortization decreased for the quarter ended September 30, 2020 as compared to the same period in 2019, primarily due to lower production volumes and a reduction in cost basis with a lower corresponding reduction in proved developed producing reserve quantities.

The reduction in cost basis is primarily due to depreciation, depletion, and amortization recorded during the prior twelve months as well as oil and natural gas property impairments recorded in the first quarter of 2020.

1 unchanged sentence

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

For the quarter ended June 30, 2020, general and administrative expenses decreased as compared to the same period in 2019, primarily due to a $3.0 million decrease in cash compensation and a $1.0 million decrease in equity-based compensation resulting from the broad workforce reduction in the first quarter of 2020.

The overall decrease was partially offset by a $1.1 million increase in allowance, recorded in the second quarter of 2020, against an outstanding long-term receivable.

For the quarter ended September 30, 2020, general and administrative expenses decreased as compared to the same period in 2019, primarily due to a $2.1 million decrease in cash compensation and a $1.9 million decrease in equity-based compensation resulting from the broad workforce reduction in the first quarter of 2020.

Interest expense .

Interest expense was lower in the second quarter of 2020 relative to the corresponding period in 2019, due to lower interest rates and lower average outstanding borrowings under our Credit Facility.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019

Interest expense was lower in the third quarter of 2020 relative to the corresponding period in 2019, due to lower interest rates and lower average outstanding borrowings under our Credit Facility.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019

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

Six Months Ended June 30,

Nine Months Ended September 30,

2020 2019 Variance

31 unchanged sentences

2 Not meaningful.

Total revenue for the six months ended June 30, 2020 decreased compared to the corresponding prior period.

Total revenue for the nine months ended September 30, 2020 decreased compared to the corresponding prior period.

The decrease in total revenue 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 in total revenue was partially offset by a gain from our commodity derivative instruments for the six months ended June 30, 2020, compared to a loss in the same period in 2019.

The overall decrease in total revenue was partially offset by an increase in the gain from our commodity derivative instruments for the nine months ended September 30, 2020, compared to the same period in 2019.

Oil and condensate sales.

Oil and condensate sales during the six months ended June 30, 2020 decreased compared to the corresponding prior period due to lower realized commodity prices and lower production volumes.

Oil and condensate sales during the nine months ended September 30, 2020 decreased compared to the corresponding prior period due to lower realized commodity prices and lower production volumes.

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

Our mineral and royalty

interest oil and condensate volumes accounted for 92% and 93% of total oil and condensate volumes for the six months ended June 30, 2020 and 2019, respectively.

Our mineral and royalty interest oil and condensate volumes accounted for 92% and 92% of total oil and condensate volumes for the nine months ended September 30, 2020 and 2019, respectively.

Natural gas and natural gas liquids sales.

Natural gas and NGL sales during the six months ended June 30, 2020 decreased compared to the corresponding prior period due to lower realized commodity prices and lower production volumes.

The decrease in natural gas and NGL production was primarily driven by lower volumes in the Haynesville/Bossier play.

Mineral and royalty interest production accounted for 74% and 67% of our natural gas volumes for the six months ended June 30, 2020 and 2019, respectively.

Natural gas and NGL sales during the nine months ended September 30, 2020 decreased compared to the corresponding prior period due to lower realized commodity prices and lower production volumes.

The decrease in natural gas and NGL 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 68% of our natural gas volumes for the nine months ended September 30, 2020 and 2019, respectively.

Gain (loss) on commodity derivative instruments.

During the six months ended June 30, 2020, we recognized a gain from our commodity derivative instruments compared to a loss in the same period in 2019.

In the six months ended June 30, 2020, we recognized $45.5 million of realized gains and $25.3 million of unrealized gains from our oil and natural gas commodity contracts, compared to $4.7 million of realized gains and $16.7 million of unrealized losses in the same period in 2019.

The unrealized gains on our commodity contracts during the six months ended June 30, 2020 were primarily driven by changes in the forward commodity price curves for oil.

During the nine months ended September 30, 2020, we recognized an increase in the gain from our commodity derivative instruments compared to the same period in 2019.

In the nine months ended September 30, 2020, we recognized $66.8 million of realized gains and $17.0 million of unrealized losses from our oil and natural gas commodity contracts, compared to $18.3 million of realized gains and $6.0 million of unrealized losses in the same period in 2019.

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

The unrealized losses on our commodity contracts during the corresponding period 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.

Lease bonus and other income for the six months ended June 30, 2020 was lower than the same period in 2019.

Leasing activity in the Permian Basin, Green River Basin, and Bakken/Three Forks made up the majority of lease bonus revenue in the six months ended June 30, 2020, while a substantial portion of the activity in the corresponding prior period came from the Permian Basin, as well as the Bakken/Three Forks, Wilcox, and Woodbine trends.

Lease bonus and other income for the nine months ended September 30, 2020 was lower than the same period in 2019.

Leasing activity in the Permian Basin, Green River Basin, and Bakken/Three Forks as well as certain surface leases in Polk County, Texas made up the majority of lease bonus revenue in the nine months ended September 30, 2020, while a substantial portion of the activity in the corresponding prior period came from the Permian Basin, as well as the Bakken/Three Forks, Wilcox, and Woodbine trends.

Operating and Other Expenses

Lease operating expense .

Lease operating expense decreased for the six months ended June 30, 2020 as compared to the same period in 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-operating working interest properties.

Lease operating expense decreased for the nine months ended September 30, 2020 as compared to the same period in 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-operating working interest properties.

Production costs and ad valorem taxes .

For the six months ended June 30, 2020, production costs and ad valorem taxes decreased as compared to the six months ended June 30, 2019, primarily as a result of lower commodity prices and lower production volumes.

For the nine months ended September 30, 2020, production costs and ad valorem taxes decreased as compared to the nine months ended September 30, 2019, primarily as a result of lower commodity prices and lower production volumes.

Exploration expense .

Exploration expense for the six months ended June 30, 2020 was minimal.

Exploration expense for the six months ended June 30, 2019 primarily related to costs incurred to acquire 3-D seismic information related to our mineral and royalty interests from a third-party service provider.

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

Exploration expense for the nine months ended September 30, 2019 primarily related to 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 .

Depreciation, depletion, and amortization decreased for the six months ended June 30, 2020 as compared to the same period in 2019, primarily due to lower production volumes and a reduction in cost basis with a lower corresponding reduction in proved developed producing reserve quantities.

Depreciation, depletion, and amortization decreased for the nine months ended September 30, 2020 as compared to the same period in 2019, primarily due to lower production volumes and a reduction in cost basis with a lower corresponding reduction in proved developed producing reserve quantities.

1 unchanged sentence

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

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

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

There were no impairments for the six months ended June 30, 2019.

Management periodically conducts an in-depth evaluation of the cost of property acquisitions, successful exploratory wells, development activity, unproved leasehold,

and mineral interests to identify impairments.

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

There were no impairments for the nine months ended September 30, 2019.

General and administrative .

For the six months ended June 30, 2020, general and administrative expenses decreased as compared to the same period in 2019, primarily due to a $4.8 million decrease in cash compensation and a $13.0 million decrease in equity-based compensation.

For the nine months ended September 30, 2020, general and administrative expenses decreased as compared to the same period in 2019, primarily due to a $6.9 million decrease in cash compensation and a $14.9 million 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 the six months ended June 30, 2020 for performance-based incentive awards due to the decrease in our common unit price period over period.

The decrease in equity-based compensation is due in part to these same workforce reductions but also due to downward cost revisions recognized in the nine months ended September 30, 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 and a $1.1 million increase in allowance, recorded in the second quarter of 2020, against an outstanding long-term receivable.

Interest expense .

Interest expense was lower in the six months ended June 30, 2020 than in the prior period primarily due to lower interest rates and lower average outstanding borrowings under our Credit Facility.

Interest expense was lower in the nine months ended September 30, 2020 than in the prior period primarily due to lower interest rates and lower average outstanding borrowings under our Credit Facility.

Liquidity and Capital Resources

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Our primary uses of cash are for distributions to our unitholders, reducing outstanding borrowings under our Credit Facility, and for investing in our business, specifically the acquisition of mineral and royalty interests and our selective participation on a non-operated working interest basis in the development of our oil and natural gas properties.

As of June 30, 2020, we had outstanding borrowings of $ 323.0 million under the Credit Facility.

In July 2020, we closed two separate transactions to sell certain mineral and royalty properties in the Permian Basin for total proceeds, after closing adjustments, of $150.1 million.

Proceeds from the asset sales were used to reduce outstanding borrowings under our Credit Facility and as of July 31, 2020, we had outstanding borrowings of $153.0 million under the Credit Facility.

In connection with the closing of these asset sales, the borrowing base under the Credit Facility was reduced from $ 460.0 million to $ 430.0 million, effective July 21, 2020.

As of September 30, 2020, we had outstanding borrowings of $ 147.0 million under the Credit Facility.

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

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In light of the challenging business environment and uncertainty caused by the pandemic, the Board 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 an increase in the quarterly distribution for the second quarter of 2020 but the distribution remains below 2019 levels.

The Board approved an increase in the quarterly distribution for the second quarter of 2020 and maintained that distribution for the third quarter of 2020 but the distribution remains below 2019 levels.

If our borrowings exceed our borrowing base, our ability to pay cash distributions to our unitholders will be limited.

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

Six Months Ended June 30,

Nine Months Ended September 30,

2020 2019 Change

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

Cash flows provided by operating activities decreased for the six months ended June 30, 2020 as compared to the same period of 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 for the six months ended June 30, 2020 compared to the same period of 2019.

Cash flows provided by operating activities decreased for the nine months ended September 30, 2020 as compared to the same period of 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 for the nine months ended September 30, 2020 compared to the same period of 2019.

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

Investing Activities .

Net cash was provided by investing activities in the six months ended June 30, 2020 as compared to net cash used in investing activities in the same period of 2019.

The change was primarily due to reduced oil and natural gas property acquisitions and expenditures, net of farmout reimbursements, and higher proceeds from the sale of oil and natural gas properties in the six months ended June 30, 2020.

Net cash was provided by investing activities in the nine months ended September 30, 2020 as compared to net cash used in investing activities in the same period of 2019.

The change was primarily due to proceeds from the sale of oil and natural gas properties as well as a decrease in the additions to oil and natural gas properties in the nine months ended September 30, 2020.

Financing Activities .

Cash flows used in financing activities increased for the six months ended June 30, 2020 as compared to the same period of 2019.

The increase was primarily due to net repayments under our Credit Facility in the six months ended June 30, 2020 as compared to net borrowings in the corresponding prior period.

Cash flows used in financing activities increased for the nine months ended September 30, 2020 as compared to the same period of 2019.

The increase was primarily due to net repayments under our Credit Facility in the nine months ended September 30, 2020 as compared to net borrowings in the corresponding prior period.

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

Development Capital Expenditures

Our 2020 total development capital expenditure budget associated with our non-operated working interests is expected to be approximately $3.5 million, net of farmout reimbursements, of which $0.9 million has been invested in the six months ended June 30, 2020.

Our 2020 total development capital expenditure budget associated with our non-operated working interests is expected to be approximately $2.0 million, net of farmout reimbursements, of which $0.8 million has been invested in the nine months ended September 30, 2020.

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

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Our Credit Facility terminates on November 1, 2022.

As of June 30, 2020, we had outstanding borrowings of $ 323.0 million at a weighted-average interest rate of 2.43 %.

As of September 30, 2020, we had outstanding borrowings of $ 147.0 million at a weighted-average interest rate of 2.15 %.

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.

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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.

The next borrowing base redetermination is expected in the fall of 2020.

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

The next borrowing base redetermination is expected in the spring of 2021.

If operators continue to shut-in production and commodity prices remain at current levels, our borrowing base could be further reduced.

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The applicable margin for the alternative base rate ranges from 0.75 % to 1.75 % and the applicable margin for LIBOR ranges from 1.75 % to 2.75 %, depending on the borrowings outstanding in relation to the borrowing base.

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.

Principal may be optionally repaid from time to time without premium or penalty, other than customary LIBOR breakage, and is required to be paid (a) if the amount outstanding exceeds the borrowing base, whether due to a borrowing base

redetermination or otherwise, in some cases subject to a cure period, or (b) at the maturity date.

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

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

As of June 30, 2020, we were in compliance with all debt covenants.

As of September 30, 2020, we were in compliance with all debt covenants.

On July 27, 2017, the U.K.

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Contractual Obligations

As of June 30, 2020, there have been no material changes to our contractual obligations previously disclosed in our 2019 Annual Report on Form 10-K.

As of September 30, 2020, there have been no material changes to our contractual obligations previously disclosed in our 2019 Annual Report on Form 10-K.

Off-Balance Sheet Arrangements

As of June 30, 2020, we did not have any material off-balance sheet arrangements.

As of September 30, 2020, we did not have any material off-balance sheet arrangements.

Critical Accounting Policies and Related Estimates

As of June 30, 2020, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our 2019 Annual Report on Form 10-K.

As of September 30, 2020, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our 2019 Annual Report on Form 10-K.

New and Revised Financial Accounting Standards

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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-Q

Item 2. Management’s Discussion and Analysis