What changed in this filing

/stocks — the workspaceLOADING

Item 2. Management’s Discussion and Analysis

2022-08-02 compared with 2022-05-03 · 133 added, 58 removed, 284 unchanged (40% of the section changed)

46 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, 2022, 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, 2022, our mineral and royalty interests were located in 41 states in the continental United States, including all of the major onshore producing basins.

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

4 unchanged sentences

Shelby Trough Development Update

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

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

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

Aethon has successfully turned eight wells to sales and has commenced operations on six additional wells under the development agreement covering Angelina County.

Aethon is currently drilling two wells and completing four wells under the separate development agreement covering San Augustine County.

Aethon’s completions are more intensive than those of prior operators in the area and result in higher initial flowback rates.

Additionally, XTO Energy has finished drilling operations and started completing the three wells on our Shelby Trough acreage in San Augustine County that were originally spud in 2019.

Austin Chalk Update

We have entered into agreements with multiple operators to drill wells in the areas of the Austin Chalk in East Texas, where we have significant acreage positions.

We have entered into agreements with multiple operators to drill wells in the Austin Chalk in East Texas, where we have significant acreage positions.

The results of our three- well test program in the Brookeland Field demonstrates that modern completion technology can greatly improve production rates and increase reserves when compared to the vintage, unstimulated wells in the Austin Chalk formation.

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

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

In addition to the test well program, twelve new horizontal wells have been drilled on our acreage to test various portions of the field across a four-county area.

Although production results have varied on those wells, the play is becoming better delineated, with consistent well performance across certain areas.

Seven operators are actively engaged in redevelopment of the field, with four rigs currently running in the play.

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

Business Environment

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

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

We have recently transitioned to a hybrid work environment offering employees the ability to work remotely most days and, subject to compliance with our health and safety guidelines, in the office on other days.

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

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

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

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

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Benchmark Prices 1

First Quarter First Quarter

Second Quarter First Quarter Second Quarter First Quarter

WTI spot oil price ($/Bbl) $ 107.76 $ 100.53 $ 73.52 $ 59.19

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Rising levels of U.S.LNG exports have been a growing source of demand and have positively impacted natural gas prices, particularly in the Gulf Coast region where the majority of our natural gas is produced.

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

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

The EIA expects high levels of U.S.

LNG exports to continue, forecasting average exports of 12.4 Bcf per day for the rest of 2022 and 12.6 Bcf per day for 2023.

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

LNG prices have been volatile in 2022 resulting from the uncertainty in the global natural gas markets leading up to and following Russia's full-scale invasion of Ukraine, as well as from weather-related fluctuations in natural gas demand.

Net natural gas exports averaged 11.2 Bcf per day in the first half of 2022, a 15% increase from the 2021 average.

On June 9, 2022, Freeport LNG shut down its Gulf Coast LNG export facility, which represents approximately 20% of the total U.S.

export capacity, due to an explosion at the facility.

The EIA expects U.S.

LNG exports to decline due to the outage at the Freeport LNG export facility, forecasting average exports of 10.5 Bcf per day for the rest of 2022 and 12.7 Bcf per day for 2023.

In a June 30, 2022 statement, Freeport LNG indicated that it "continues to target year-end for a return to full production." The EIA forecast reflects the assumption that global natural gas demand remains strong and that expected additional U.S.

LNG export capacity comes online.

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Rotary Rig Count 1

First Quarter First Quarter

Second Quarter First Quarter Second Quarter First Quarter

Oil 594 531 372 324

Natural gas 157 137 98 92

Other 2 2 — 1

Total 753 670 470 417

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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 461 268 513 307

Midwest 535 317 623 401

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

Our open oil and natural gas derivative contracts as of March 31, 2022 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 June 30, 2022 are detailed in Note 4 - Commodity Derivative Financial Instruments to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

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

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

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

As of March 31, 2022, we have also hedged 72% and 16% of our available natural gas hedge volumes for 2022 and 2023, respectively.

As of June 30, 2022, we have hedged 88% and 15% of our available oil and condensate hedge volumes for 2022 and 2023, respectively.

As of June 30, 2022, we have also hedged 76% and 30% of our available natural gas hedge volumes for 2022 and 2023, respectively.

We intend to continuously monitor the production from our assets and the commodity price environment, and will, from time to time, add additional hedges within the percentages described above related to such production.

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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,

2022 2021 2022 2021

(in thousands)

7 unchanged sentences

Unrealized (gain) loss on commodity derivative instruments (35,103) 42,135 53,673 65,494

(Gain) loss on sale of assets, net (17) — (17) —

Adjusted EBITDA 112,838 78,363 211,594 138,347

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Results of Operations

Three Months Ended March 31, 2022 Compared to Three Months Ended March 31, 2021

Three Months Ended June 30, 2022 Compared to Three Months Ended June 30, 2021

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

Three Months Ended March 31,

Three Months Ended June 30,

2022 2021 Variance

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

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

The decrease in total revenue from the corresponding period is primarily due to an increase in unrealized losses from our commodity derivative instruments and was partially offset by an increase in oil and condensate sales, natural gas and NGL sales, and lease bonus and other income.

Total revenue for the quarter ended June 30, 2022 increased compared to the quarter ended June 30, 2021.

The increase in total revenue from the corresponding period is primarily due to an increase in sales of oil and condensate, natural gas, and NGLs in addition to unrealized gains from our commodity derivative instruments partially offset by a decrease in our lease bonus and other income.

Oil and condensate sales.

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

Our mineral and royalty interest oil and condensate volumes accounted for 94% and 92% of total oil and condensate volumes for quarters ended March 31, 2022 and 2021, respectively.

Oil and condensate sales increased for the quarter ended June 30, 2022 as compared to the corresponding period in 2021 primarily due to higher realized commodity prices.

Our mineral and royalty interest oil and condensate volumes accounted for 92% of total oil and condensate volumes for quarters ended June 30, 2022 and 2021.

Natural gas and natural gas liquids sales.

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

Natural gas and NGL sales increased for the quarter ended June 30, 2022 as compared to the corresponding prior period.

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

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

The decrease in natural gas and NGL production was primarily driven by the natural decline in producing wells in the Shelby Trough outpacing new activity from the Aethon development program, which has not yet fully ramped up, in addition to lower working interest volumes in the area as a result of the farmout agreements put in place in 2017.

Mineral and royalty interest production accounted for 90% and 83% of our natural gas volumes for the quarters ended June 30, 2022 and 2021, respectively.

Gain (loss) on commodity derivative instruments.

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

During the second quarter of 2022, we recognized a decrease in losses from our commodity derivative instruments compared to the same period in 2021.

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

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The changes in fair value result from new positions and settlements that may occur during each reporting period, as well as the relationships between contract prices and the associated forward curves.

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

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

The unrealized losses for the same period in 2021 were primarily driven by changes in the forward commodity price curves for oil.

For the three months ended June 30, 2022, we recognized $62.5 million of realized losses and $35.1 million of unrealized gains from our oil and natural gas commodity contracts, compared to $17.4 million of realized losses and $42.1 million of unrealized losses in the same period in 2021.

The unrealized gains on our commodity contracts during the second quarter of 2022 and the unrealized losses for the same period in 2021 were primarily driven by changes in the forward commodity price curves for oil and natural gas during each period.

Lease bonus and other income.

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

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

Leasing activity in the Wolfcamp play made up the majority of lease bonus and other income for the first quarter of 2022, while a substantial portion of the first quarter 2021 activity came from leasing activity in the Austin Chalk play.

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

Leasing activity in the Austin Chalk play made up the majority of lease bonus and other income for the second quarter of 2022, and a substantial portion for the second quarter of 2021.

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 increased for the quarter ended March 31, 2022 as compared to the same period in 2021, primarily due to higher nonrecurring service-related expenses, including workovers.

Lease operating expense decreased for the quarter ended June 30, 2022 as compared to the same period in 2021 due to a decrease in working interest production volumes as a result of the TLW divestiture in the third quarter of 2021 and continued declines from our remaining working interest properties.

Due to the fixed costs from these remaining properties, our lease operating expense per BOE increased from the comparative period.

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, 2022, production costs and ad valorem taxes increased as compared to the quarter ended March 31, 2021, primarily due to higher production taxes stemming from rising commodity prices partially offset by lower ad valorem tax estimates.

For the quarter ended June 30, 2022, production costs and ad valorem taxes increased as compared to the quarter ended June 30, 2021, primarily due to higher production taxes stemming from rising commodity prices and higher ad valorem tax estimates.

Exploration expense .

Exploration expense typically consists of dry-hole expenses, delay rentals, and geological and geophysical costs, including seismic costs, and is expensed as incurred under the successful efforts method of accounting.

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

Exploration expense was minimal for the quarter ended June 30, 2022 and in the corresponding prior period in 2021.

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, 2022 as compared to the same period in 2021, primarily due to a reduction in cost basis with a lower corresponding reduction in proved developed producing reserve quantities.

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

Depreciation, depletion, and amortization decreased for the quarter ended June 30, 2022 as compared to the same period in 2021, primarily due to lower natural gas production.

General and administrative .

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

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

For the quarter ended June 30, 2022, general and administrative expenses increased slightly as compared to the same period in 2021, primarily due to an increase in cash compensation.

Interest expense .

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

Interest expense was lower in the second quarter of 2022 relative to the corresponding period in 2021, due to lower average outstanding borrowings under our Credit Facility partially offset by higher interest rates.

Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021

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

Six Months Ended June 30,

2022 2021 Variance

(Dollars in thousands, except for realized prices)

Oil and condensate (MBbls) 1,730 1,689 41 2.4 %

Natural gas (MMcf) 1

25,654 30,586 (4,932) (16.1) %

Equivalents (MBoe) 6,006 6,787 (781) (11.5) %

Equivalents/day (MBoe) 33.2 37.5 (4.3) (11.5) %

Realized prices, without derivatives:

Oil and condensate ($/Bbl) $ 98.34 $ 58.09 $ 40.25 69.3 %

Natural gas ($/Mcf) 1

7.29 3.25 4.04 124.3 %

Equivalents ($/Boe) $ 59.45 $ 29.10 $ 30.35 104.3 %

Oil and condensate sales $ 170,127 $ 98,112 $ 72,015 73.4 %

Natural gas and natural gas liquids sales 1

186,935 99,370 87,565 88.1 %

Lease bonus and other income 7,103 9,890 (2,787) (28.2) %

Revenue from contracts with customers 364,165 207,372 156,793 75.6 %

Gain (loss) on commodity derivative instruments (147,369) (87,362) (60,007) 68.7 %

Total revenue $ 216,796 $ 120,010 $ 96,786 80.6 %

Operating expenses:

Lease operating expense $ 6,360 $ 6,501 $ (141) (2.2) %

Production costs and ad valorem taxes 33,453 21,138 12,315 58.3 %

Exploration expense 182 1,075 (893) (83.1) %

Depreciation, depletion, and amortization 22,810 31,428 (8,618) (27.4) %

General and administrative 26,282 25,039 1,243 5.0 %

Other expense:

Interest expense 2,571 2,838 (267) (9.4) %

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.

Total revenue for the six months ended June 30, 2022 increased compared to the corresponding prior period.

The increase in total revenue is due to increased sales of oil and condensate, natural gas, and NGLs for the six months ended June 30, 2022 compared to the same period in 2021.

The overall increase in total revenue was partially offset by an increased loss from our commodity derivative instruments and a decrease in lease bonus and other income for the six months ended June 30, 2022 compared to the same period in 2021.

Oil and condensate sales.

Oil and condensate sales during the six months ended June 30, 2022 increased compared to the corresponding prior period due to higher realized commodity prices.

Our mineral and royalty interest oil and condensate volumes accounted for 93% of total oil and condensate volumes for both the six months ended June 30, 2022 and 2021.

Natural gas and natural gas liquids sales.

Natural gas and NGL sales during the six months ended June 30, 2022 increased compared to the corresponding prior period due to higher realized commodity prices partially offset by lower production volumes.

Mineral and royalty interest production accounted for 89% and 84% of our natural gas volumes for the six months ended June 30, 2022 and 2021, respectively.

Gain (loss) on commodity derivative instruments.

During the six months ended June 30, 2022, we recognized an increased loss from our commodity derivative instruments compared to the same period in 2021.

In the six months ended June 30, 2022, we recognized $93.7 million of realized losses and $53.7 million of unrealized losses from our oil and natural gas commodity contracts, compared to $21.9 million of realized gains and $65.5 million of unrealized losses in the same period in 2021.

The unrealized losses on our commodity contracts during the six months ended June 30, 2022 and 2021 were primarily driven by changes in the forward commodity price curves for oil and natural gas during each period.

Lease bonus and other income.

Lease bonus and other income for the six months ended June 30, 2022 was lower than the same period in 2021.

Leasing activity in the Wolfcamp play made up the majority of lease bonus and other income for the six months ended June 30, 2022, and for the corresponding prior period.

Operating and Other Expenses

Lease operating expense .

Lease operating expense decreased for the six months ended June 30, 2022 as compared to the same period in 2021 due to a decrease in working interest production volumes as a result of the TLW divestiture in the third quarter of 2021 and continued declines from our remaining working interest properties.

Due to the fixed costs from these remaining properties, our lease operating expense per BOE increased from the comparative period.

Production costs and ad valorem taxes .

For the six months ended June 30, 2022, production costs and ad valorem taxes increased as compared to the six months ended June 30, 2021, primarily due to higher production taxes stemming from rising commodity prices and higher ad valorem tax estimates.

Exploration expense .

Exploration expense for the six months ended June 30, 2022 was minimal.

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

Depreciation, depletion, and amortization .

Depreciation, depletion, and amortization decreased for the six months ended June 30, 2022 as compared to the same period in 2021, primarily due to lower natural gas production volumes.

General and administrative .

For the six months ended June 30, 2022, general and administrative expenses increased as compared to the same period in 2021, primarily due to an increase in cash compensation and a $0.7 million increase in equity incentive compensation.

The increase in equity incentive compensation was due to higher costs recognized for performance-based incentive awards resulting from larger upward movements in our common unit price during the six months ended June 30, 2022 compared to the corresponding prior period.

Interest expense .

Interest expense was lower in the six months ended June 30, 2022 than in the prior period primarily due to lower average outstanding borrowings under our Credit Facility partially offset by higher interest rates.

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

As of June 30, 2022, we had outstanding borrowings of $86.0 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.

4 unchanged sentences

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

Three Months Ended March 31,

Six Months Ended June 30,

2022 2021 Change

5 unchanged sentences

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 increased for the three months ended March 31, 2022 as compared to the same period of 2021.

The increase was primarily due to higher oil and condensate sales and natural gas and NGL sales due to higher realized commodity prices in the three months ended March 31, 2022 compared to the same period of 2021.

Cash flows provided by operating activities increased for the six months ended June 30, 2022 as compared to the same period of 2021.

The increase was primarily due to higher oil and condensate sales and natural gas and NGL sales due to higher realized commodity prices in the six months ended June 30, 2022 compared to the same period of 2021.

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

Investing Activities .

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

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

Net cash used in investing activities in the six months ended June 30, 2022 decreased as compared to the same period of 2021.

The decrease was primarily due to minimal cash paid for acquisitions of oil and natural gas properties in the six months ended June 30, 2022 compared to the same period of 2021.

Financing Activities .

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

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

Cash flows used in financing activities increased for the six months ended June 30, 2022 as compared to the same period of 2021.

The increase was primarily due to higher distributions to unitholders.

Development Capital Expenditures

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

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

3 unchanged sentences

Our Credit Facility terminates on November 1, 2024.

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

As of June 30, 2022, we had outstanding borrowings of $86.0 million at a weighted-average interest rate of 4.12%.

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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Outstanding borrowings under the Credit Facility bear interest at a floating rate elected by us equal to an alternative base rate (which is equal to the greatest of the Prime Rate, the Federal Funds effective rate plus 0.50%, or 1-month LIBOR plus 1.00%) or LIBOR, in each case, plus the applicable margin.

As of December 31, 2021 and March 31, 2022, the applicable margin for the alternative base rate ranged from 1.50% to 2.50% and the applicable margin for LIBOR ranged from 2.50% to 3.50%, depending on the borrowings outstanding in relation to the borrowing base.

As of December 31, 2021 and June 30, 2022, the applicable margin for the alternative base rate ranged from 1.50% to 2.50% and the applicable margin for LIBOR ranged from 2.50% to 3.50%, depending on the borrowings outstanding in relation to the borrowing base.

We are obligated to pay a quarterly commitment fee ranging from a 0.375% to 0.500% annualized rate on the unused portion of the borrowing base, depending on the amount of the borrowings outstanding in relation to the borrowing base.

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

As of June 30, 2022, we were in compliance with all debt covenants.

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

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Contractual Obligations

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

As of June 30, 2022, there have been no material changes to our contractual obligations previously disclosed in our 2021 Annual Report on Form 10-K.

Critical Accounting Policies and Related Estimates

As of March 31, 2022, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our 2021 Annual Report on Form 10-K.

As of June 30, 2022, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our 2021 Annual Report on Form 10-K.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-Q

Item 2. Management’s Discussion and Analysis