What changed in this filing

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Item 2. Management’s Discussion and Analysis

2023-08-01 compared with 2023-05-02 · 137 added, 57 removed, 270 unchanged (42% of the section changed)

41 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, 2023, 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, 2023, 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 68,000 producing wells.

4 unchanged sentences

Shelby Trough Development Update

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

Aethon has successfully turned 4 wells to sales and has another nine wells awaiting completion operations under the separate development agreement covering San Augustine County.

Additionally, XTO Energy has resumed drilling on our Shelby Trough acreage in San Augustine County and has one well currently awaiting completion operations.

Aethon continues to perform with drilling and completing wells according to our development agreements.

Aethon has five rigs currently on our acreage in the Shelby Trough.

Aethon has successfully turned 16 wells to sales and has commenced operations on 18 additional wells under the development agreement covering Angelina County.

Aethon has successfully turned six wells to sales and has another nine wells awaiting completion operations under the separate development agreement covering San Augustine County.

Additionally, XTO Energy has turned four wells to sales in the second quarter and has two wells currently awaiting completion operations.

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.

The results of our 2021 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.

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

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

The results of the 2021 three well test program in the Brookeland Field demonstrated that modern completion technology has the potential to greatly improve production rates and increase reserves when compared to the vintage, unstimulated wells in the Austin Chalk formation.

Eight operators are actively engaged in redevelopment of the field.

We have also reached an agreement with one of these operators to drill 10 wells in the field over the next two years.

To date, 26 wells with modern completions are now producing in the field, and an additional three wells are currently either being drilled or completed.

Business Environment

2 unchanged sentences

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

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.

Commodity prices decreased from the prior period ended March 31, 2022, due to several factors, including reduced demand for natural gas and rising global oil inventories.

Natural gas prices decreased in the first quarter of 2023 as a result of reduced consumption due to the early emergence of warmer than expected weather conditions in the first two months of the quarter.

Commodity prices during the six months ended June 30, 2023 decreased from the corresponding prior period, due to several factors, including reduced demand for natural gas and rising global oil inventories.

Natural gas prices decreased in the first quarter of 2023 and remained flat in the second quarter as a result of increases in dry natural gas production, lower-than-average consumption due to mild winter weather conditions in the first two months of the year, and the resulting higher-than-average storage inventories.

The current price environment remains uncertain as responses to elevated inflation and the conflict in Ukraine continue to evolve.

The EIA expects relatively flat U.S.

natural gas production, increases in LNG exports, and increased consumption in the electric power sector will raise prices in 2023.

natural gas production and year-over-year growth in consumption in the electric power sector to raise prices in the second half of 2023.

Given the dynamic nature of these events, we cannot reasonably estimate the period of time that these market conditions will persist.

2 unchanged sentences

Benchmark Prices 1

First Quarter First Quarter

Second Quarter First Quarter Second Quarter First Quarter

WTI spot oil price ($/Bbl) $ 70.66 $ 75.68 $ 107.76 $ 100.53

4 unchanged sentences

Rotary Rig Count 1

First Quarter First Quarter

Second Quarter First Quarter Second Quarter First Quarter

Oil 545 592 594 531

Natural gas 124 160 157 137

Other 5 3 2 2

Total 674 755 753 670

12 unchanged sentences

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

First Quarter First Quarter

Second Quarter First Quarter Second Quarter First Quarter

East 643 335 461 268

Midwest 705 421 535 317

5 unchanged sentences

The EIA expects an increase in U.S.

LNG exports resulting from three major LNG export projects under construction that will come online by the end of 2024.

Net natural gas exports averaged 11.6 Bcf per day in the first quarter of 2023, a 10% increase from the 2022 average.

The EIA forecasts average exports of 12.2 Bcf per day for the rest of 2023 and 12.7 Bcf per day for 2024.

LNG exports resulting from two major LNG export projects under construction that will come online by the end of 2024.

Net natural gas exports averaged 12.1 Bcf per day in the second quarter of 2023, a 14% increase from the 2022 average.

The EIA forecasts average exports of 12.3 Bcf per day for the remainder of 2023 and 13.3 Bcf per day for 2024.

The EIA forecast reflects the assumption that production remains flat and that expected additional U.S.

39 unchanged sentences

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, 2023 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, 2023 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, but not required, to hedge up to 90% of such volumes for the first 24 months, 70% for months 25 through 36, and 50% for months 37 through 48.

As of March 31, 2023, we had hedged 67% and 22% of our available oil and condensate hedge volumes for 2023 and 2024, respectively.

As of March 31, 2023, we had also hedged 64% and 41% of our available natural gas hedge volumes for 2023 and 2024, respectively.

As of June 30, 2023, we had hedged 74% and 62% of our available oil and condensate hedge volumes for 2023 and 2024, respectively.

As of June 30, 2023, we had also hedged 67% and 82% of our available natural gas hedge volumes for 2023 and 2024, 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.

8 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,

2023 2022 2023 2022

(in thousands)

7 unchanged sentences

Unrealized (gain) loss on commodity derivative instruments 16,881 (35,103) (22,105) 53,673

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

Adjusted EBITDA 109,245 112,838 219,173 211,594

5 unchanged sentences

Results of Operations

Three Months Ended March 31, 2023 Compared to Three Months Ended March 31, 2022

Three Months Ended June 30, 2023 Compared to Three Months Ended June 30, 2022

The following table shows our production, revenue, and operating expenses for the periods presented:

Three Months Ended March 31,

Three Months Ended June 30,

2023 2022 Variance

30 unchanged sentences

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, 2023 increased compared to the quarter ended March 31, 2022.

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

Total revenue for the quarter ended June 30, 2023 decreased compared to the quarter ended June 30, 2022.

The decrease in total revenue from the corresponding period is primarily due to a decrease in oil and condensate sales and, natural gas and NGL sales, and was partially offset by a gain from our commodity derivative instruments compared to a loss in the prior period.

Oil and condensate sales.

Oil and condensate sales decreased for the quarter ended March 31, 2023 as compared to the corresponding period in 2022 primarily due to lower realized commodity prices and production volumes.

Our mineral and royalty interest oil and condensate volumes accounted for 92% and 94% of total oil and condensate volumes for quarters ended March 31, 2023 and 2022, respectively.

Oil and condensate sales decreased for the quarter ended June 30, 2023 as compared to the corresponding period in 2022 primarily due to lower realized commodity prices and production volumes.

The decrease in oil and condensate production was driven by decreases in mineral and royalty production in the Permian Basin and the Eagle Ford.

Our mineral and royalty interest oil and condensate volumes accounted for 93% and 92% of total oil and condensate volumes for quarters ended June 30, 2023 and 2022, respectively.

Natural gas and natural gas liquids sales.

Natural gas and NGL sales decreased for the quarter ended March 31, 2023 as compared to the corresponding prior period.

Natural gas and NGL sales decreased for the quarter ended June 30, 2023 as compared to the corresponding prior period.

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

The increase in natural gas and NGL production was primarily driven by new development in the Haynesville/Bossier play trend.

Mineral and royalty interest production accounted for 94% and 89% of our natural gas volumes for the quarters ended March 31, 2023 and 2022, respectively.

The increase in natural gas and NGL production was primarily driven by new development in the Haynesville/Bossier play trend, including new activity from the Aethon development program in the Shelby Trough.

Mineral and royalty interest production accounted for 93% and 90% of our natural gas volumes for the quarters ended June 30, 2023 and 2022, respectively.

Gain (loss) on commodity derivative instruments.

During the first quarter of 2023, we recognized a gain from our commodity derivative instruments compared to a loss in the same period in 2022.

During the second quarter of 2023, we recognized a gain from our commodity derivative instruments compared to a loss in the same period in 2022.

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, 2023, we recognized $13.3 million of realized gains and $39.0 million of unrealized gains from our oil and natural gas commodity contracts, compared to $31.2 million of realized losses and $88.8 million of unrealized losses in the same period in 2022.

The unrealized gains on our commodity contracts during the first quarter of 2023 were primarily driven by changes in the forward commodity price curves for natural gas.

The unrealized losses for the same period in 2022 were primarily driven by changes in the forward commodity price curves for oil and natural gas.

For the three months ended June 30, 2023, we recognized $28.2 million of realized gains and $16.9 million of unrealized losses from our oil and natural gas commodity contracts, compared to $62.5 million of realized losses and $35.1 million of unrealized gains in the same period in 2022.

The unrealized losses on our commodity contracts during the second quarter of 2023 were primarily driven by changes in the forward commodity price curves for natural gas.

The unrealized gains for the same period in 2022 were primarily driven by changes in the forward commodity price curves for natural gas.

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 2023 was lower than the same period in 2022.

Leasing activity in the Haynesville/Bossier and Wolfcamp plays made up the majority of lease bonus and other income for the first quarter of 2023, while a substantial portion of the first quarter 2022 activity came from leasing activity in the Wolfcamp play.

Lease bonus and other income for the second quarter of 2023 was higher than the same period in 2022.

Leasing activity in the Bakken/Three Forks and Haynesville/Bossier plays made up the majority of lease bonus and other income for the second quarter of 2023, while the majority of the second quarter 2022 activity came from leasing activity in the Austin Chalk play.

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, 2023 as compared to the same period in 2022, primarily due to lower nonrecurring service-related expenses, including workovers.

Lease operating expense decreased for the quarter ended June 30, 2023 as compared to the same period in 2022, primarily due to lower 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, 2023, production costs and ad valorem taxes decreased as compared to the quarter ended March 31, 2022, primarily due to lower production taxes stemming from falling commodity prices partially offset by higher ad valorem tax estimates.

For the quarter ended June 30, 2023, production costs and ad valorem taxes decreased as compared to the quarter ended June 30, 2022, primarily due to lower production taxes and lower ad valorem tax estimates stemming from lower 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 was minimal for the quarter ended March 31, 2023 and in the corresponding prior period in 2022.

Exploration expense was minimal for the quarter ended June 30, 2023 and in the corresponding prior period in 2022.

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 increased for the quarter ended March 31, 2023 as compared to the same period in 2022, primarily due to increased production partially offset by 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, 2023 as compared to the same period in 2022, primarily due to a reduction in cost basis with a lower corresponding reduction in proved developed producing reserve quantities partially offset by increased production.

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, 2023, general and administrative expenses decreased slightly as compared to the same period in 2022, primarily due to a $2.4 million decrease in equity compensation offset by a $1.7 million increase in cash compensation.

The decrease in equity incentive compensation was due to lower costs recognized for performance-based incentive awards due to downward movements in our common unit price period over period.

For the quarter ended June 30, 2023, general and administrative expenses decreased slightly as compared to the same period in 2022, primarily due to a $0.8 million decrease in cash compensation.

The decrease in cash compensation was driven by projected underperformance relative to performance targets under our short-term cash incentive plan compared with projected overperformance in the prior period.

Interest expense .

Interest expense was lower in the first quarter of 2023 relative to the corresponding period in 2022, due to lower average outstanding borrowings under our Credit Facility and partially offset by higher interest rates.

Interest expense was lower in the second quarter of 2023 relative to the corresponding period in 2022, primarily due to lower average outstanding borrowings under our Credit Facility.

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022

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

Six Months Ended June 30,

2023 2022 Variance

(Dollars in thousands, except for realized prices)

Oil and condensate (MBbls) 1,639 1,730 (91) (5.3) %

Natural gas (MMcf) 1

31,121 25,654 5,467 21.3 %

Equivalents (MBoe) 6,826 6,006 820 13.7 %

Equivalents/day (MBoe) 37.7 33.2 4.5 13.6 %

Realized prices, without derivatives:

Oil and condensate ($/Bbl) $ 74.72 $ 98.34 $ (23.62) (24.0) %

Natural gas ($/Mcf) 1

3.18 7.29 (4.11) (56.4) %

Equivalents ($/Boe) $ 32.45 $ 59.45 $ (27.00) (45.4) %

Oil and condensate sales $ 122,460 $ 170,127 $ (47,667) (28.0) %

Natural gas and natural gas liquids sales 1

99,042 186,935 (87,893) (47.0) %

Lease bonus and other income 6,502 7,103 (601) (8.5) %

Revenue from contracts with customers 228,004 364,165 (136,161) (37.4) %

Gain (loss) on commodity derivative instruments 63,574 (147,369) 210,943 143.1 %

Total revenue $ 291,578 $ 216,796 $ 74,782 34.5 %

Operating expenses:

Lease operating expense $ 5,534 $ 6,360 $ (826) (13.0) %

Production costs and ad valorem taxes 25,511 33,453 (7,942) (23.7) %

Exploration expense 8 182 (174) (95.6) %

Depreciation, depletion, and amortization 21,568 22,810 (1,242) (5.4) %

General and administrative 24,502 26,282 (1,780) (6.8) %

Other expense:

Interest expense 1,459 2,571 (1,112) (43.3) %

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, 2023 increased compared to the corresponding prior period.

The increase in total revenue is due to a gain from our commodity derivative instruments for the six months ended June 30, 2023 compared to a loss in the same period in 2022.

The overall increase in total revenue was partially offset by decreases 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, 2023 decreased compared to the corresponding prior period due to lower realized commodity prices and a decrease in production.

The decrease in oil and condensate production was driven by decreases in mineral and royalty production in the Permian Basin and the Eagle Ford.

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, 2023 and 2022.

Natural gas and natural gas liquids sales.

Natural gas and NGL sales during the six months ended June 30, 2023 decreased compared to the corresponding prior period due to lower realized commodity prices partially offset by higher production volumes.

The increase in natural gas and NGL production was driven by increases in royalty interest production volumes, primarily within the Haynesville/Bossier play, including new activity from the Aethon development program in the Shelby Trough.

Mineral and royalty interest production accounted for 94% and 89% of our natural gas volumes for the six months ended June 30, 2023 and 2022, respectively.

Gain (loss) on commodity derivative instruments.

During the six months ended June 30, 2023, we recognized a gain from our commodity derivative instruments compared to a loss for the same period in 2022.

In the six months ended June 30, 2023, we recognized $41.5 million of realized gains and $22.1 million of unrealized gains from our oil and natural gas commodity contracts, compared to $93.7 million of realized losses and $53.7 million of unrealized losses in the same period in 2022.

The unrealized gains on our commodity contracts during the six months ended June 30, 2023 were primarily driven by changes in the forward commodity price curves for oil and natural gas.

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

Lease bonus and other income.

Lease bonus and other income for the six months ended June 30, 2023 was lower than the same period in 2022.

Leasing activity in the Bakken/Three Forks and Haynesville/Bossier plays made up the majority of lease bonus and other income for the six months ended June 30, 2023, while a substantial portion of the activity in the corresponding prior period came from leasing activity in the Wolfcamp play.

Operating and Other Expenses

Lease operating expense .

Lease operating expense decreased for the six months ended June 30, 2023 as compared to the same period in 2022, primarily due to lower nonrecurring service-related expenses, including workovers.

Production costs and ad valorem taxes .

For the six months ended June 30, 2023, production costs and ad valorem taxes decreased as compared to the six months ended June 30, 2022, primarily due to lower production taxes stemming from lower commodity prices and lower ad valorem tax estimates.

Exploration expense .

Exploration expense was minimal for the six months ended June 30, 2023 and for the six months ended June 30, 2022.

Depreciation, depletion, and amortization .

Depreciation, depletion, and amortization decreased slightly for the six months ended June 30, 2023 as compared to the same period in 2022, primarily due to a reduction in cost basis with a lower corresponding reduction in proved developed producing reserve quantities partially offset by increased production.

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

General and administrative .

For the six months ended June 30, 2023, general and administrative expenses decreased as compared to the same period in 2022, primarily due to a $2.6 million decrease in equity compensation which was partially offset by a $1.0 million increase in cash compensation.

The increase in cash compensation was driven by an increase in salaries as well as a separation payment related to the departure of a senior executive in the first quarter of 2023.

The overall increase in cash compensation was partially offset by projected underperformance relative to performance targets under our short-term cash incentive plan compared with projected overperformance in the prior period.

The decrease in equity incentive compensation was due to lower costs recognized for performance-based incentive awards resulting from downward movements in our common unit price during the six months ended June 30, 2023 compared to upward movements in our common unit price in the corresponding prior period.

Interest expense .

Interest expense was lower in the six months ended June 30, 2023 than in the prior period primarily due to lower average outstanding borrowings under our Credit Facility.

Liquidity and Capital Resources

1 unchanged sentence

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, 2023, no balance was outstanding under the Credit Facility.

As of June 30, 2023, no balance was outstanding under the Credit Facility.

We have the option to redeem Series B cumulative convertible preferred units beginning on November 28, 2023.

6 unchanged sentences

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

Three Months Ended March 31,

Six Months Ended June 30,

2023 2022 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, 2023 as compared to the same period of 2022.

Cash flows provided by operating activities increased for the six months ended June 30, 2023 as compared to the same period of 2022.

The increase was primarily due to higher cash settlements received on our commodity derivative instruments as compared to cash settlements paid in the same period of 2022.

Investing Activities .

Net cash used in investing activities in the three months ended March 31, 2023 increased as compared to the same period of 2022.

The increase was primarily due to increased cash additions to oil and natural gas properties, net of farmout reimbursements in the three months ended March 31, 2023 as compared to the corresponding prior period.

Net cash used in investing activities in the six months ended June 30, 2023 increased as compared to the same period of 2022.

The increase was primarily due to increased additions to oil and natural gas properties, net of farmout reimbursements in the six months ended June 30, 2023 as compared to the corresponding prior period.

Financing Activities .

Cash flows used in financing activities increased for the three months ended March 31, 2023 as compared to the same period of 2022.

The increase was primarily due to higher distributions to unitholders in the three months ended March 31, 2023 as compared to the corresponding prior period.

Cash flows used in financing activities increased for the six months ended June 30, 2023 as compared to the same period of 2022.

The increase was primarily due to higher distributions to unitholders in the six months ended June 30, 2023 as compared to the corresponding prior period.

Development Capital Expenditures

Our 2023 capital expenditure budget associated with our non-operated working interests is expected to be approximately $7.9 million, net of farmout reimbursements, of which $1.9 million has been invested in the three months ended March 31, 2023.

Our 2023 capital expenditure budget associated with our non-operated working interests is expected to be approximately $4.9 million, net of farmout reimbursements, of which $2.5 million has been invested in the six months ended June 30, 2023.

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

5 unchanged sentences

Our Credit Facility terminates on October 31, 2027.

As of March 31, 2023, no balance was outstanding under the Credit Facility.

As of June 30, 2023, no balance was outstanding under the Credit Facility.

The borrowing base is redetermined semi-annually, usually in April and October and is derived from the value of our oil and natural gas properties as determined by the lender syndicate using pricing assumptions that often differ from the current market for future prices.

6 unchanged sentences

Concurrent with the Credit Facility amendment, the borrowing base under the Credit Facility was increased to $550.0 million and we elected to lower commitments under the Credit Facility from $400.0 million to $375.0 million.

The April 2023 borrowing base redetermination reaffirmed the borrowing base at $550.0 million with cash commitments at $375.0 million.The next semi-annual redetermination is scheduled for October 2023.

The April 2023 borrowing base redetermination reaffirmed the borrowing base at $550.0 million with cash commitments at $375.0 million.

The next semi-annual redetermination is scheduled for October 2023.

In October 2022, the Credit Facility was amended to replace the LIBOR rate with the secured overnight financing rate published by the Federal Reserve Bank of New York ("SOFR").

Outstanding borrowings under the Credit Facility bear interest at a floating rate elected by us equal to a base rate (which is a rate per annum equal to the highest of (a) the Prime Rate in effect on such day, (b) the Federal Funds Rate in effect on such day plus 0.50%, and (c) Adjusted Term SOFR for a one month tenor in effect on such day plus 1.00%) or Adjusted Term SOFR, in each case, plus the applicable margin.

As of December 31, 2022 and March 31, 2023, the applicable margin for the alternative base rate ranged from 1.50% to 2.50% and the Adjusted Term SOFR margin ranged from 2.50% to 3.50%, depending on the borrowings outstanding in relation to the borrowing base.

As of December 31, 2022 and June 30, 2023, the applicable margin for the alternative base rate ranged from 1.50% to 2.50% and the Adjusted Term SOFR margin 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.

8 unchanged sentences

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, 2023, we were in compliance with all debt covenants.

As of June 30, 2023, we were in compliance with all debt covenants.

Contractual Obligations

As of March 31, 2023, there have been no material changes to our contractual obligations previously disclosed in our 2022 Annual Report on Form 10-K.

As of June 30, 2023, there have been no material changes to our contractual obligations previously disclosed in our 2022 Annual Report on Form 10-K.

Critical Accounting Policies and Related Estimates

As of March 31, 2023, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our 2022 Annual Report on Form 10-K.

As of June 30, 2023, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our 2022 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