What changed in this filing

/stocks — the workspaceLOADING

Item 2. Management’s Discussion and Analysis

2021-08-03 compared with 2021-05-04 · 180 added, 88 removed, 276 unchanged (49% of the section changed)

33 unchanged sentences

• the ability of our operators to keep pace with technological advancements;

• conservation measures and general concern about the environmental impact of the production and use of fossil fuels;

• cybersecurity incidents, including data security breaches or computer viruses;

• certain factors discussed elsewhere in this filing.

6 unchanged sentences

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

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

As of June 30, 2021, our mineral and royalty interests were located in 41 states in the continental United States, including all of the major onshore producing basins.

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

3 unchanged sentences

Recent Developments

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

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

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

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

Shelby Trough Update

Angelina County

Aethon has successfully drilled the initial two wells under the development agreement covering Angelina County and expects to turn those wells to sales in the second quarter of 2021.

Under the terms of that agreement, Aethon will drill a minimum of four wells on our acreage in the first program year ending in September 2021, escalating to a minimum of 15 wells per program year starting with the third program year.

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

Under the terms of the agreement, Aethon must drill a minimum of four wells on our acreage in the first program year ending in September 2021, escalating to a minimum of 15 wells per program year starting with the third program year.

San Augustine County

In March 2021, we reached an agreement with XTO Energy, Inc.

(“XTO”) to partition jointly owned working interests in the Brent Miller development area in San Augustine County.

Under the partition agreement, we exchanged working interests with XTO in certain existing and proposed drilling units, resulting in each company holding 100% of the working interests in their respective partitioned units.

In May 2021, we entered into an agreement with Aethon to develop certain of our undeveloped acreage in San Augustine County, including the working interests resulting from the partition agreement discussed above.

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.

In May 2021, we entered into an agreement with Aethon to develop certain of our undeveloped acreage in San Augustine County.

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

The agreement calls for a minimum of five wells to be drilled in the initial program year, which begins in the third quarter of 2021, increasing to a minimum of 12 wells per year beginning with the fourth program year.

Our development agreement with Aethon and related drilling commitments covering its San Augustine County acreage is independent of the development agreement and associated commitments covering Angelina County.

In May 2021, we entered into a new farmout agreement (the “Second Canaan Farmout”) with Canaan Resource Partners ("Canaan").

The Second Canaan Farmout supersedes and replaces the original farmout agreement with Canaan with respect to the area in San Augustine County covered by the Aethon development agreement.

The Second Canaan Farmout covers part of our share of working interests under active development by Aethon in San Augustine County, Texas and continues until May 2031, unless earlier terminated in accordance to the terms of the agreement.

Canaan will earn 80% of our working interest in the partitioned acreage from XTO (up to a maximum of 40% on an 8/8ths basis) and 50% of our working interest in other areas (up to a maximum of 12.5% on an 8/8ths basis) in wells drilled and operated by Aethon in accordance with the development agreement.

Canaan is obligated to fund the development of all wells drilled by Aethon in the initial program year and thereafter, Canaan has certain rights and options to continue funding our working interests for the duration of the Second Canaan Farmout.

As of June 30, 2021, no wells had been drilled under the Second Canaan Farmout.

We will receive an ORRI before payout and an increased ORRI after payout on all wells drilled under the Second Canaan Farmout.

Austin Chalk Update

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Under the terms of the agreement, the operators will participate in three test wells targeting the Austin Chalk formation.

Assuming the test well program is successful, we anticipate entering into separate agreements with each operator to further develop the acreage.

In April 2021, we also entered into an agreement with a large, private independent operator ("Operator") to drill and complete multiple Austin Chalk wells on our acreage within East Texas in 2021.

If the initial wells are successful, the Operator has the option to expand the Austin Chalk development program on additional acreage owned by us.

Acquisition Update

In May 2021, we entered into an agreement to acquire mineral and royalty acreage in the northern Midland Basin for total consideration of $20.7 million.

The purchase price will consist of $10.0 million in cash and $10.7 million in our common units.

The acquisition is expected to close in the second quarter of 2021.

Two of the wells under the test program are currently being drilled, and the third well has been permitted.

In addition to the test program, we have entered into a development agreement with one of the operators and are negotiating separate agreements with each remaining operator to further develop the acreage.

In April 2021, we also entered into an agreement with a large, private independent operator to drill and complete multiple Austin Chalk wells on our acreage within East Texas.

We expect the operator to spud two wells on the acreage in 2021.

If the initial wells are successful, the operator has the option to expand the Austin Chalk development program on additional additional acreage owned by us.

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.

The first well under this agreement is scheduled to be spud in the third or fourth quarter of 2021.

If the initial wells are successful, the operator has the option to expand the Austin Chalk drilling program over a significant acreage position, the majority of which is owned and controlled by us.

New Sustainability Initiative

In July of 2021, we announced a new sustainability initiative in which we will use proceeds from surface use waivers on our mineral acreage supporting solar development to purchase carbon credits in an effort to offset part of the CO 2 emissions associated with our mineral production.

Business Environment

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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.

With widespread availability of vaccines, the U.S.

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

We have provisionally implemented a hybrid work approach, providing employees flexibility with work arrangements and the ability to collaborate with colleagues.

All employees are assigned remote work days along with in-office work days.

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

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

We continue to monitor the spread of COVID-19 in the community, especially those resulting from new variants, and we will adjust our workplace policies accordingly.

Commodity Prices and Demand

4 unchanged sentences

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

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

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

Commodity prices improved in late 2020 and had fully recovered to 2018 levels by July of 2021, reflecting expectations of rising demand as both COVID-19 vaccination rates and global economic activity increased, combined with ongoing crude oil production limits from members of the Organization of the Petroleum Exporting Countries and its broader partners.

However, the current price environment remains uncertain as new strains of the virus are driving increases in reported cases and responses to the COVID-19 pandemic continue to evolve.

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

While we use derivative instruments to partially mitigate the impact of commodity price volatility, our revenues and operating results depend significantly upon the prevailing prices for oil and natural gas.

The 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.

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

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

1 unchanged sentence

Effective November 3, 2020, the borrowing base redetermination reduced the borrowing base from $430.0 million to $400.0 million, and effective April 30, 2021, the borrowing base was reaffirmed at $400.0 million.

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

The next borrowing base redetermination is scheduled for October 2021.

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 and fourth quarters of 2020, but the distribution remains below 2019 levels.

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

Benchmark Prices 1

First Quarter First Quarter

Second Quarter First Quarter Second Quarter First Quarter

WTI spot oil price ($/Bbl) $ 73.52 $ 59.19 $ 39.27 $ 20.51

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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.

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

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

Rotary Rig Count 1

First Quarter First Quarter

Second Quarter First Quarter Second Quarter First Quarter

Oil 372 324 188 624

Natural gas 98 92 75 102

Other — 1 2 2

Total 470 417 265 728

10 unchanged sentences

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

The EIA estimates that natural gas inventories concluded the withdrawal season in March 2021 at almost 1.8 Tcf, or 2% lower than the previous five-year average.

The EIA estimates that natural gas inventories will conclude the injection season in October 2021 at 3.6 Tcf, which is 3% lower than the previous five-year average.

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

First Quarter First Quarter

Second Quarter First Quarter Second Quarter First Quarter

East 513 307 639 382

Midwest 623 401 740 476

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

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

Our open oil and natural gas derivative contracts as of March 31, 2021 are detailed in Note 4 - Commodity Derivative Financial Instruments to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

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, 2021 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 March 31, 2021, we have hedged 100% of our available oil and condensate hedge volumes and 81% of our available natural gas hedge volumes for 2021.

As of March 31, 2021, we have also hedged 22% of our available oil and condensate hedge volumes for 2022.

As of June 30, 2021, we have hedged 96% of our available oil and condensate hedge volumes and 84% of our available natural gas hedge volumes for 2021.

As of June 30, 2021, we have also hedged 68% of our available oil and condensate hedge volumes and 67% of our natural gas hedge volumes for 2022.

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.

1 unchanged sentence

Non-GAAP Financial Measures

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.

Adjusted EBITDA and Distributable cash flow are supplemental non-GAAP financial measures used by our management and external users of our financial statements such as investors, research analysts, and others, to assess the financial performance of our assets and our ability to sustain distributions over the long term without regard to financing methods, capital structure, or historical cost basis.

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

4 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 March 31,

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

2021 2020 2021 2020

(in thousands)

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Results of Operations

Three Months Ended March 31, 2021 Compared to Three Months Ended March 31, 2020

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

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

Three Months Ended March 31,

Three Months Ended June 30,

2021 2020 Variance

16 unchanged sentences

Revenue from contracts with customers 117,922 57,703 60,219 104.4 %

Gain (loss) on commodity derivative instruments (27,882) 90,011 (117,893) NM 2

Gain (loss) on commodity derivative instruments (59,480) (19,174) (40,306) 210.2 %

Total revenue $ 58,442 $ 38,529 $ 19,913 51.7 %

4 unchanged sentences

Depreciation, depletion, and amortization 15,796 19,193 (3,397) (17.7) %

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

General and administrative 12,187 11,501 686 6.0 %

5 unchanged sentences

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 quarter ended March 31, 2021 decreased compared to the quarter ended March 31, 2020.

The decrease in total revenue from the corresponding period is due to a loss on our commodity derivative instruments in the first quarter of 2021 compared to a gain in the first quarter of 2020, a decrease in oil and condensate sales, and a decrease in lease bonus and other income.

The overall decrease in total revenue was partially offset by an increase in natural gas and NGL sales.

Total revenue for the quarter ended June 30, 2021 increased compared to the quarter ended June 30, 2020.

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

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

Oil and condensate sales.

Oil and condensate sales decreased for the quarter ended March 31, 2021 as compared to the corresponding period in 2020 due to lower production volumes partially offset by higher realized commodity prices.

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

mineral and royalty interest oil and condensate volumes accounted for 92% of total oil and condensate volumes for both quarters ended March 31, 2021 and 2020.

Oil and condensate sales increased for the quarter ended June 30, 2021 as compared to the corresponding period in 2020 due to higher realized commodity prices.

Our mineral and royalty interest oil and condensate volumes accounted for 92% and 93% of total oil and condensate volumes for the quarters ended June 30, 2021 and 2020, respectively.

Natural gas and natural gas liquids sales.

Natural gas and NGL sales increased for the quarter ended March 31, 2021 as compared to the corresponding prior period due to higher realized commodity prices partially offset by lower production volumes.

Natural gas and NGL sales increased for the quarter ended June 30, 2021 as compared to the corresponding prior period due to higher realized commodity prices partially offset by lower production volumes.

Contributing to this increase was approximately $5.6 million in additional natural gas revenue recognized in the second quarter of 2021 due to realized price differentials during the February 2021 storms exceeding our original projections.

The decrease in natural gas and NGL production was driven by decreases in working interest production volumes, primarily within the Haynesville/Bossier play.

Mineral and royalty interest production accounted for 82% and 73% of our natural gas volumes for the quarters ended March 31, 2021 and 2020, respectively.

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

Gain (loss) on commodity derivative instruments.

During the first quarter of 2021, we recognized a loss from our commodity derivative instruments compared to a gain in the same period in 2020.

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

Cash settlements we receive represent realized gains, while cash settlements we pay represent realized losses related to our commodity derivative instruments.

1 unchanged sentence

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 March 31, 2021, we recognized $4.5 million of realized losses and $23.4 million of unrealized losses from our oil and natural gas commodity contracts, compared to $9.0 million of realized gains and $81.1 million of unrealized gains in the same period in 2020.

The unrealized losses on our commodity contracts during the first quarter of 2021 and the unrealized gains for the same period in 2020 were primarily driven by changes in the forward commodity price curves for oil.

For the three months ended June 30, 2021, we recognized $17.4 million of realized losses and $42.1 million of unrealized losses from our oil and natural gas commodity contracts, compared to $36.6 million of realized gains and $55.7 million of unrealized losses in the same period in 2020.

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

The unrealized losses for the same period in 2020 were primarily driven by changes in the forward commodity price curves 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 first quarter of 2021 was lower than the same period in 2020.

Leasing activity in the Austin Chalk play made up the majority of lease bonus revenue in the first quarter of 2021, while a substantial portion of first quarter 2020 activity came from the Permian Basin, Green River Basin, and Bakken/Three Forks.

Lease bonus and other income for the second quarter of 2021 was higher than the same period in 2020.

Leasing activity in the Austin Chalk and proceeds from surface use waivers on our mineral acreage supporting solar development in Mississippi made up the majority of lease bonus and other income for the second quarter of 2021, while a substantial portion of second quarter 2020 activity came from the Permian Basin.

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 March 31, 2021 as compared to the same period in 2020, 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 increased for the quarter ended June 30, 2021 as compared to the same period in 2020, primarily due to higher nonrecurring service-related expenses, including workovers.

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 March 31, 2021, production costs and ad valorem taxes decreased as compared to the quarter ended March 31, 2020, primarily due to lower ad valorem tax estimates for the 2021 tax year partially offset by higher production costs attributable to our natural gas and NGL revenues due to higher commodity prices.

For the quarter ended June 30, 2021, production costs and ad valorem taxes decreased as compared to the quarter ended June 30, 2020, primarily due to lower ad valorem tax estimates partially offset by higher production taxes due to higher commodity prices.

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 the three months ended March 31, 2021 primarily related to a dry hole drilled during the period.

Exploration expense was minimal in the corresponding prior period in 2020.

Exploration expense was minimal for the quarter ended June 30, 2021 and in the corresponding prior period in 2020.

Depreciation, depletion, and amortization .

2 unchanged sentences

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 March 31, 2021 as compared to the same period in 2020, primarily due to lower production volumes and a reduction in cost basis with a lower corresponding reduction in proved developed producing reserve quantities.

Depreciation, depletion, and amortization decreased for the quarter ended June 30, 2021 as compared to the same period in 2020, primarily due to lower production volumes and a reduction in cost basis with a lower corresponding reduction in proved developed producing reserve quantities.

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

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 March 31, 2021, general and administrative expenses increased as compared to the same period in 2020, primarily due to a $6.4 million increase in equity-based compensation that was partially offset by a $4.8 million decrease related to restructuring charges recognized in the first quarter of 2020 and a $1.0 million decrease in cash compensation.

The lower equity-based compensation expense in 2020 relative to the current period was primarily due to downward cost revisions recognized in 2020 for performance-based incentive awards due to changes in our common unit price period over period.

For the quarter ended June 30, 2021, general and administrative expenses increased as compared to the same period in 2020, primarily due to a $1.6 million increase in cash compensation and a $0.5 million increase in equity compensation.

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

The overall increase was partially offset by a $1.1 million allowance recorded against an outstanding long-term receivable in the prior comparative period with no similar allowance recorded for the quarter ended June 30, 2021.

Interest expense .

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

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

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020

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

Six Months Ended June 30,

2021 2020 Variance

(Dollars in thousands, except for realized prices)

Oil and condensate (MBbls) 1,689 2,027 (338) (16.7) %

Natural gas (MMcf) 1

30,586 36,702 (6,116) (16.7) %

Equivalents (MBoe) 6,787 8,144 (1,357) (16.7) %

Equivalents/day (MBoe) 37.5 44.7 (7.2) (16.1) %

Realized prices, without derivatives:

Oil and condensate ($/Bbl) $ 58.09 $ 38.24 $ 19.85 51.9 %

Natural gas ($/Mcf) 1

3.25 1.82 1.43 78.6 %

Equivalents ($/Boe) $ 29.10 $ 17.74 $ 11.36 64.0 %

Oil and condensate sales $ 98,112 $ 77,510 $ 20,602 26.6 %

Natural gas and natural gas liquids sales 1

99,370 66,953 32,417 48.4 %

Lease bonus and other income 9,890 6,283 3,607 57.4 %

Revenue from contracts with customers 207,372 150,746 56,626 37.6 %

Gain (loss) on commodity derivative instruments (87,362) 70,837 (158,199) NM 2

Total revenue $ 120,010 $ 221,583 $ (101,573) (45.8) %

Operating expenses:

Lease operating expense $ 6,501 $ 7,120 $ (619) (8.7) %

Production costs and ad valorem taxes 21,138 21,931 (793) (3.6) %

Exploration expense 1,075 24 1,051 4,379.2 %

Depreciation, depletion, and amortization 31,428 42,375 (10,947) (25.8) %

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

General and administrative 25,039 23,357 1,682 7.2 %

Other expense:

Interest expense 2,838 7,391 (4,553) (61.6) %

1 As a mineral and royalty interest owner, we are often provided insufficient and inconsistent data on NGL volumes by our operators.

As a result, we are unable to reliably determine the total volumes of NGLs associated with the production of natural gas on our acreage.

Accordingly, no NGL volumes are included in our reported production;

however, revenue attributable to NGLs is included in our natural gas revenue and our calculation of realized prices for natural gas.

2 Not meaningful.

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

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

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

Oil and condensate sales.

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

The decrease in oil and condensate production was primarily driven by lower production volumes in the Permian Basin.

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

Natural gas and natural gas liquids sales.

Natural gas and NGL sales during the six months ended June 30, 2021 increased compared to the corresponding prior period due to higher realized commodity prices partially offset by lower production volumes.

The decrease in natural gas and NGL production was driven by decreases in working interest production volumes, primarily within the Haynesville/Bossier play.

Mineral and royalty interest production accounted for 82% and 74% of our natural gas volumes for the six months ended June 30, 2021 and 2020, respectively.

Gain (loss) on commodity derivative instruments.

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

In the six months ended June 30, 2021, we recognized $21.9 million of realized losses and $65.5 million of unrealized losses from our oil and natural gas commodity contracts, compared to $45.5 million of realized gains and $25.3 million of unrealized gains in the same period in 2020.

The unrealized losses on our commodity contracts during the six months ended June 30, 2021 were primarily driven by changes in the forward commodity price curves for oil and natural gas.

The unrealized gains on our commodity contracts during the corresponding period in 2020 were primarily driven by changes in the forward commodity price curves for oil.

Lease bonus and other income.

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

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

Operating and Other Expenses

Lease operating expense .

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

Production costs and ad valorem taxes .

For the six months ended June 30, 2021, production costs and ad valorem taxes decreased as compared to the six months ended June 30, 2020, primarily due to lower ad valorem tax estimates partially offset by higher production taxes due to higher commodity prices.

Exploration expense .

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

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

Depreciation, depletion, and amortization .

Depreciation, depletion, and amortization decreased for the six months ended June 30, 2021 as compared to the same period in 2020, primarily due to lower production volumes and a reduction in cost basis with a lower corresponding reduction in proved developed producing reserve quantities.

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

Impairment of oil and natural gas properties .

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

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

Impairments totaled $51.0 million for the 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, 2021.

General and administrative .

For the six months ended June 30, 2021, general and administrative expenses increased as compared to the same period in 2020, primarily due to a $0.7 million increase in cash compensation and a $7.0 million increase in equity incentive compensation.

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

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

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

Interest expense .

Interest expense was lower in the six months ended June 30, 2021 than in the prior period primarily due to 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 March 31, 2021, we had outstanding borrowings of $111.0 million under the Credit Facility.

As of June 30, 2021, we had outstanding borrowings of $96.0 million under the Credit Facility.

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

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

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 and fourth quarters 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.

We intend to finance our future acquisitions with cash generated from operations, borrowings from our Credit Facility, proceeds from any future issuances of equity and debt, and proceeds from asset sales.

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

Three Months Ended March 31,

Six Months Ended June 30,

2021 2020 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 three months ended March 31, 2021 as compared to the same period of 2020.

The decrease was primarily due to net cash paid on settlements of commodity derivative instruments in the three months ended March 31, 2021 compared to net cash received in the same period of 2020.

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

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

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

Investing Activities .

Net cash was used in investing activities in the three months ended March 31, 2021 as compared to net cash provided by investing activities in the same period of 2020.

The change was primarily due to proceeds from the sale of oil and natural gas properties and farmout reimbursements received in the first quarter of 2020 with no similar activities in the first quarter of 2021.

These changes were partially offset by a decrease in additions to oil and natural gas properties.

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

The change was primarily due to cash paid for acquisitions of oil and natural gas properties in the six months ended June 30, 2021 compared to minimal cash paid for acquisitions in the same period of 2020.

Financing Activities .

Cash flows used in financing activities decreased for the three months ended March 31, 2021 as compared to the same period of 2020.

The decrease was primarily due to lower distributions to common unitholders in the three months ended March 31, 2021 as compared to the corresponding prior period.

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

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

Development Capital Expenditures

Our 2021 capital expenditure budget associated with our non-operated working interests is expected to be approximately $5.0 million, net of farmout reimbursements, of which $0.2 million has been invested in the three months ended March 31, 2021.

Our 2021 capital expenditure budget associated with our non-operated working interests is expected to be approximately $5.0 million, net of farmout reimbursements, of which $2.6 million has been invested in the six months ended June 30, 2021.

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

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Our Credit Facility terminates on November 1, 2024.

As of March 31, 2021, we had outstanding borrowings of $111.0 million at a weighted-average interest rate of 2.37%.

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.

As of June 30, 2021, we had outstanding borrowings of $96.0 million at a weighted-average interest rate of 2.60%.

agent’s normal lending criteria.

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

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In these circumstances, the borrowing base will be adjusted by the value attributed to the terminated hedge positions or the oil and natural gas property interests sold in the most recent borrowing base.

Please see Item 5 of Part II of this quarterly report for a more detailed description of the amendment to the Credit Facility effective April 30, 2021.

The next semi-annual redetermination is scheduled for October 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.

As of March 31, 2021 and December 31, 2020, the applicable margin for the alternative base rate ranged from 1.00% to 2.00% and the applicable margin for LIBOR ranged from 2.00% to 3.00%, depending on the borrowings outstanding in relation to the borrowing base.

Effective April 30, 2021, the LIBOR margin was increased to between 2.50% and 3.50% and the alternative base rate margin was increased to between 1.50% and 2.50%.

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

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

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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total debt to EBITDAX of 3.5:1.0 or less and a current ratio of 1.0:1.0 or greater as defined in the credit agreement.

Distributions are not permitted if there is a default under the credit agreement (including the failure to satisfy one of the financial covenants), if the availability under the Credit Facility is less than 10% of the lenders' commitments, or if total debt to EBITDAX is less than 3.0.

The lenders have the right to accelerate all of the indebtedness under the credit agreement upon the occurrence and during the continuance of any event of default, and the credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy, and change of control.

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 March 31, 2021, we were in compliance with all debt covenants.

As of June 30, 2021, we were in compliance with all debt covenants.

On March 5, 2021, the U.K.

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Contractual Obligations

As of March 31, 2021, there have been no material changes to our contractual obligations previously disclosed in our 2020 Annual Report on Form 10-K.

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

Off-Balance Sheet Arrangements

As of March 31, 2021, we did not have any material off-balance sheet arrangements.

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

Critical Accounting Policies and Related Estimates

As of March 31, 2021, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our 2020 Annual Report on Form 10-K.

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

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