What changed in this filing

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Item 7. Management’s Discussion and Analysis

2024-02-20 compared with 2023-02-23 · 81 added, 134 removed, 303 unchanged (42% of the section changed)

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"Management’s Discussion and Analysis of Financial Condition and Results of Operations" in our 2022 Annual Report on Form 10-K, which was filed with the SEC on February 22, 2023.

We are one of the largest owners and managers of oil and natural gas mineral interests in the United States.

Our principal business is maximizing the value of our existing portfolio of mineral and royalty assets through active management and expanding our asset base through acquisitions of additional mineral and royalty interests.

We maximize value through marketing our mineral assets for lease, creatively structuring the terms on those leases to encourage and accelerate drilling activity, and selectively participating alongside our lessees on a working interest basis.

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

As of December 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.

These non-cost-bearing interests include ownership in over 68,000 producing wells.

These non-cost-bearing interests include ownership in approximately 68,000 producing wells.

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

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Recent Developments

TLW Divestiture

In the third quarter of 2021, we closed on the divestiture of our wholly owned subsidiary, TLW Investments, L.L.C.

("TLW"), effective September 1, 2021 for total proceeds of $0.2 million.

TLW holds non-operating working interests and overriding royalty interests primarily located in Oklahoma and Texas.

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

In Angelina County, Texas, ten wells are currently producing under our development agreement with Aethon, and another ten wells are being drilled or completed.

Under a separate development agreement with Aethon in San Augustine Texas, four wells are currently producing and another six wells are either drilling or awaiting completion operations.

Shelby Trough Development Update

In Angelina County, Texas, 24 wells are currently producing under our development agreement with Aethon, and another 20 wells are being drilled or completed.

Under a separate development agreement with Aethon in San Augustine County, Texas, 13 wells are currently producing, and another four wells are either drilling or awaiting completion operations.

In December 2023, we received notice that Aethon was exercising the “time-out” provisions under its joint exploration agreements with us in Angelina and San Augustine counties in East Texas.

When natural gas prices fall below specified thresholds, Aethon may elect to temporarily suspend its drilling obligations for up to nine consecutive months and a maximum of 18 total months in any 48-month period.

Aethon has not previously invoked the time-out provisions under the agreements.

The time-out provisions apply only to drilling obligations and associated development activity occurring after December 2023.

Based on ongoing discussions with Aethon, we do not expect material changes for wells on which drilling operations had begun prior to the invocation of the time-out in December 2023.

We continue working closely with Aethon to finalize development plans going forward and assess the effect of the temporary suspension of drilling obligations and any potential longer-term impacts.

Austin Chalk Update

We own a large mineral position in the Brookeland Austin Chalk play in East Texas.

To date, eighteen new generation, multi-stage completion wells have turned to sales across the Polk, Jasper, Newton area.

Production results have proven that new completion technology can improve well performance in the play.

We expect additional drilling by multiple operators over this area in the future.

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

To date, 29 wells with modern completions are now producing in the field.

Business Environment

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

Commodity prices continued to recover in 2022, due to several factors, including higher demand for oil, natural gas, and natural gas liquids ("NGLs") from the lows of the pandemic, ongoing crude oil production limits from members of the Organization of the Petroleum Exporting Countries and its broader partners, and supply constraints due to Russia's military invasion into Ukraine and the subsequent sanctions imposed on Russia.

The invasion occurred in March 2022 when oil inventories were already low, and the possibility of sanctions or physical disruptions to Russia's oil production led to higher prices.

Crude oil prices have fallen since then mainly because of slowing growth in global economic activity and oil consumption but remain above pre-pandemic levels.

Natural gas prices remained high for much of 2022 as a result of increased demand for LNG exports and lower production compared with the end of 2021.

However, prices decreased in the fourth quarter as a result of warmer-than-normal temperatures across much of the U.S.

and a decrease in export capacity resulting from the closure of the Freeport LNG Gulf Coast export facility in June 2022.

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

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

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

Energy Information Administration ("EIA") forecasts natural gas prices to be slightly higher in 2024 because of slowing growth in natural gas production and increasing U.S.

LNG exports, particularly following the addition of new export capacity expected toward the end of the year.

The slowing growth reflects a drop in natural gas production associated with oil drilling in the Permian Basin.

However, the EIA expects upward price pressures will be limited by relatively flat consumption of natural gas in the electric power sector and persistently high inventories.

For much of 2023, oil prices were relatively flat.

In September 2023, oil prices increased after Saudi Arabia extended its voluntary crude oil production cuts through the end of the year and U.S.

commercial crude oil inventories fell to the lowest levels since early 2022.

Despite reduced production targets by members of OPEC+, prices decreased in the fourth quarter based on ongoing concerns about global oil demand growth and on rising global oil inventories.

The EIA expects that while OPEC+ production cuts will lead to global oil inventory withdrawals during the first quarter of 2024, global inventories will build over the final three quarters of 2024 as slowing demand growth once again is outpaced by rising supply growth.

However, heightened tensions around the critical Red Sea shipping channel and other developments in the Middle East have added upward price pressure since early December and have the potential to disrupt global oil trade flows and drive up global oil prices further should those tensions persist or escalate.

Given the dynamic nature of these events, along with the volatile geopolitical conflicts in Ukraine, we cannot reasonably estimate how long these 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.

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From November to March, storage levels typically decline as utility companies draw natural gas from storage to meet increased heating demand due to colder weather.

In order to maintain sufficient storage levels for increased seasonal demand, a portion of natural gas production during the summer

months must be used for storage injection.

In order to maintain sufficient storage levels for increased seasonal demand, a portion of natural gas production during the summer months must be used for storage injection.

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.

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Natural Gas Exports

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.

As of February 2023, the plant has received small amounts of natural gas from pipelines and has resumed limited operations.

The EIA believes increases in U.S.

natural gas production, relatively flat LNG exports, and declining domestic consumption in the electric power and industrial sectors will limit upward pressure on prices in 2023.

The EIA forecasts average exports of 11.8 Bcf per day for 2023.

The EIA expects exports of natural gas, both by pipeline and as LNG, will increase in 2024.

The EIA forecasts average exports of 12.1 Bcf per day for 2024, a 2% increase from 2023 levels.

In January 2024, the Biden administration announced that approvals for pending and future applications for certain new LNG facilities were being paused pending a review by the DOE that aims to assess whether climate effects should be more heavily considered in the authorization process for such LNG export projects.

It is too early to know the outcome of this review and any impact the results of such review may have on LNG export growth.

How We Evaluate Our Operations

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Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end user markets.

The EIA expects increases in U.S.

natural gas production, relatively flat LNG exports, and declining domestic consumption in the electric power and industrial sectors will limit upward pressure on prices in 2023.

We enter into derivative instruments to partially mitigate the impact of commodity price volatility on our cash generated from operations.

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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 year ended December 31, 2022 increased compared to the year ended December 31, 2021.

The increase in total revenue from the corresponding period is primarily due to higher realized commodity prices partially offset by lower production volumes.

A decrease in the loss on commodity derivative instruments in 2022 further contributed to the overall increase in revenue.

Total revenue for the year ended December 31, 2023 decreased compared to the year ended December 31, 2022.

The decrease in total revenue from the corresponding period is primarily due to lower realized commodity prices partially offset by an increase in production volumes and a gain on commodity derivative instruments in 2023 compared to a loss in 2022.

Oil and condensate sales.

Oil and condensate sales for the year ended December 31, 2022 were higher than the corresponding period in 2021 due to higher realized commodity prices partially offset by lower production volumes.

The decrease in oil and condensate production was primarily due to reduced production volumes from the Bakken/Three Forks play

The decrease in Bakken/Three Forks production was driven by normal production declines with less new development activity.

Our mineral and royalty interest oil and condensate volumes accounted for 93% of total oil and condensate volumes for each of the years ended December 31, 2022 and 2021.

Oil and condensate sales for the year ended December 31, 2023 were lower than the corresponding period in 2022 due to lower realized commodity prices partially offset by higher production volumes.

The increase in oil and condensate production was primarily due to increased production volumes in the Permian Basin.

and royalty interest oil and condensate volumes accounted for 94% and 93% of total oil and condensate volumes for each of the years ended December 31, 2023 and 2022, respectively.

Natural gas and natural gas liquids sales.

Natural gas and NGL sales increased for the year ended December 31, 2022 as compared to the year ended December 31, 2021 due to higher realized commodity prices 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 Shelby Trough play.

Natural gas and NGL sales decreased for the year ended December 31, 2023 as compared to the year ended December 31, 2022 due to lower realized commodity prices offset by higher production volumes.

The increase in natural gas and NGL production was 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 94% and 92% of our natural gas volumes for the years ended December 31, 2023 and 2022, respectively.

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

During 2022, we recognized $203.2 million of realized losses and $82.5 million of unrealized gains from our commodity derivatives, compared to $112.9 million of realized losses and $33.5 million of unrealized losses in 2021.

The unrealized gains on our commodity contracts in 2022 and unrealized losses in 2021 were both primarily driven by changes in the forward commodity price curves for oil and natural gas.

During 2023, we recognized $82.7 million of realized gains and $8.4 million of unrealized gains from our commodity derivatives, compared to $203.2 million of realized losses and $82.5 million of unrealized gains in 2022.

The unrealized gains on our commodity contracts in 2023 were primarily driven by changes in the forward commodity price curves for natural gas and in 2022 by changes in the forward commodity price curves for both oil and natural gas.

Lease bonus and other income .

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Lease bonus income 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 was lower for the year ended December 31, 2022, as compared to the same period in 2021.

Leasing activity in the Wolfcamp and Haynesville/Bossier plays made up the majority of lease bonus and other income in 2022.

Leasing activity in the Austin Chalk and Wolfcamp plays, as well as proceeds from surface use waivers on our mineral acreage supporting solar development in Mississippi, Texas, and California made up the majority of lease bonus and other income in 2021.

Lease bonus and other income was slightly lower for the year ended December 31, 2023, as compared to the same period in 2022.

Leasing activity in the Haynesville/Bossier and Wolfcamp plays made up the majority of lease bonus and other income in 2023 and 2022.

Operating Expenses

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

Lease operating expense decreased in 2022 as compared to 2021, primarily due to a decrease in variable costs as a result of lower production from our non-operated working interest properties.

Lease operating expense decreased in 2023 as compared to 2022, primarily due to a reduction in variable costs as a result of lower production from our non-operated working interest properties.

Production costs and ad valorem taxes.

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

For the year ended December 31, 2022, production and ad valorem taxes increased as compared to the year ended December 31, 2021, as a result of higher commodity prices and higher ad valorem tax estimates.

For the year ended December 31, 2023, production and ad valorem taxes decreased as compared to the year ended December 31, 2022, as a result of 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 for 2022 was minimal.

Exploration expense for 2021 primarily related to a dry hole drilled in the first quarter of 2021.

Exploration expense for 2023 significantly increased due to costs incurred to acquire seismic information related to our mineral and royalty interests.

Depreciation, depletion, and amortization.

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

Depreciation, depletion, and amortization expense decreased for the year ended December 31, 2022 as compared to 2021, primarily due to lower production volumes and a reduction in cost basis.

The reduction in cost basis is primarily due to continued depreciation, depletion, and amortization.

Depreciation, depletion, and amortization expense decreased for the year ended December 31, 2023 as compared to 2022, 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.

General and administrative.

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

For the year ended December 31, 2022, general and administrative expenses increased compared to 2021, primarily due to a $1.9 million increase in cash compensation and a $4.8 million increase in equity-based compensation.

The increase in

cash compensation was driven by projected outperformance relative to performance targets under our short-term cash incentive plan.

The increase in equity-based compensation was due to higher costs recognized for performance-based incentive awards resulting from upward movements in our common unit price during 2022 compared to 2021.

The overall increase was partially offset by a $2.1 million recovery in allowance against an outstanding long-term receivable.

For the year ended December 31, 2023, general and administrative expenses decreased compared to 2022, primarily due to a $6.6 million decrease in equity-based compensation from lower costs recognized for performance-based incentive awards resulting from downward movements in our common unit price during 2023 compared to upward movements in our

common unit price during 2022.

The overall decrease was partially offset by increases in consulting costs of $2.6 million related to internal projects and a non-recurring $2.1 million recovery in allowance against an outstanding long-term receivable in 2022.

Other Expense

Interest expense.

For the year ended December 31, 2022, interest expense increased compared to 2021, primarily due to higher interest rates under our Credit Facility.

For the year ended December 31, 2023, interest expense decreased compared to 2022, primarily due to lower average outstanding borrowings resulting from fully paying down our Credit Facility in the first quarter of 2023.

Interest expense in 2023 consisted primarily of commitment fees and amortization of debt issuance costs.

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated from operations, borrowings under our Credit Facility, and proceeds from the issuance of equity and debt.

Our primary uses of cash are for distributions to our unitholders, reducing outstanding borrowings under our Credit Facility, 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.

We have the option to redeem Series B cumulative convertible preferred units beginning on November 28, 2023 (see Note 12).

Our primary sources of liquidity are cash generated from operations and borrowings under our Credit Facility.

Our primary uses of cash are for distributions to our unitholders, reducing outstanding borrowings under our Credit Facility as applicable, and for investing in our business.

We have the option to redeem all or a portion (equal to or greater than $100 million) of the Series B cumulative convertible preferred units until February 26, 2024 at a redemption price of $21.41 per Series B cumulative convertible preferred unit, which is equal to 105% of par value.

Thereafter, we may redeem the preferred units at par value, equal to $20.39, within a 90-day period on each second anniversary following November 28, 2023.

See "Note 12 – Preferred Units" to the consolidated financial statements included elsewhere in this Annual Report for additional information.

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.

We intend to finance any 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.

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

Over the long-term, we intend to finance our working interest capital needs with our executed farmout agreements and internally generated cash flows, although at times we may fund a portion of these expenditures through other financing sources such as borrowings under our Credit Facility.

On October 30, 2023, the Board authorized a $150.0 million unit repurchase program which authorizes us to make repurchases on a discretionary basis.

The program will be funded from our cash on hand or through borrowings under the Credit Facility.

Any repurchased units will be cancelled.

See "Note 14 – Common Units" to the consolidated financial statements included elsewhere in this Annual Report for additional information.

Year Ended December 31, 2023 Compared to Year Ended December 31, 2022

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Cash provided by operating activities for 2023 increased as compared to 2022.

The increase was primarily due an increase in oil and condensate sales revenue and natural gas and NGL sales revenue due to higher realized commodity prices in 2022 compared to the same period of 2021.

The overall increase was partially offset by an increase in net cash paid on settlements of commodity derivative instruments.

The increase was primarily due to an increase in net cash received on settlements of commodity derivative instruments in 2023 compared to net cash paid in the same period of 2022.

The overall increase was partially offset by a decrease in oil and condensate sales revenue and natural gas and NGL sales revenue due to lower realized commodity prices.

Investing Activities .

Net cash used in investing activities for 2022 decreased as compared to 2021.

The change was primarily due to minimal acquisition activity and lower net oil and gas capital expenditures in 2022 compared to the same period in 2021.

Net cash used in investing activities for 2023 increased as compared to 2022.

The change was primarily due to increased acquisition activity and higher net oil and natural gas capital expenditures in 2023 compared to the same period in 2022.

Financing Activities .

Cash flows used in financing activities for 2023 increased as compared to 2022.

The increase was primarily due to higher distributions paid to common unitholders as well as higher net repayments under our Credit Facility in 2022 compared with 2021.

The increase was primarily due to higher distributions paid to common unitholders partially offset by lower net repayments under our Credit Facility in 2023 compared with 2022.

Development Capital Expenditures

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The timing, size, and nature of acquisitions are unpredictable.

Our 2023 capital expenditure budget associated with our non-operated working interests is expected to be approximately $6.9 million, net of farmout reimbursements.

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

Our 2024 capital expenditure budget associated with our non-operated working interests is expected to be approximately $2.3 million.

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

We spent approximately $4.8 million and $0.6 million associated with our non-operated working interests, net of farmout reimbursements during 2023 and 2022, respectively.

During the year ended December 31, 2023, we acquired mineral and royalty interests for cash consideration of $14.6 million, including capitalized direct transaction costs.

The acquisitions were funded with cash from operating activities and were primarily located in the Gulf Coast land region.

Our current commercial strategy includes the continuation of meaningful, targeted mineral and royalty acquisitions to complement our existing positions.

We had no material acquisition activity during 2022.

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The commitment of the lenders equals the least of the aggregate maximum credit amount, the then-effective borrowing base, and the aggregate elected commitment, as it may be adjusted from time to time.

The amount of the borrowing base is redetermined semi-annually, usually in October and April, 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.

We and the lenders (at the direction of two-thirds of the lenders) each have discretion to request a borrowing base redetermination one time between scheduled redeterminations.

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

The borrowing base is also adjusted if we terminate our hedge positions or sell oil and natural gas property interests that have a combined value exceeding 5% of the current borrowing base.

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.

The April and October 2021 and April 2022 borrowing base redeterminations reaffirmed the borrowing base at $400.0 million.

In October 2022, we revised and amended the Credit Facility to extend the maturity date from November 1, 2024 to October 31, 2027.

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 amount of the borrowing base is redetermined semi-annually, usually in October and April.

In October 2022, we revised and amended the Credit Facility to extend the maturity date from November 1, 2024 to October 31, 2027, increased the borrowing base to $550.0 million and elected to lower commitments under the Credit Facility to $375.0 million.

The April 2023 borrowing base redetermination reaffirmed the borrowing base at $550.0 million and the October 2023 borrowing base redetermination increased the borrowing base to $580.0 million.

After both redeterminations we elected to maintain cash commitments at $375.0 million.

The next semi-annual redetermination is scheduled for April 2024.

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

As of December 31, 2022, the alternative base rate margin 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.

Principal may be optionally repaid from time to time without premium or penalty, other than customary SOFR 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.

Our credit agreement contains various affirmative, negative, and financial maintenance covenants.

These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates, and entering into certain derivative agreements, as well as require the maintenance of certain financial ratios.

The credit agreement contains two financial covenants:

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 greater 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.

We are subject to various affirmative, negative, and financial maintenance covenants which pose limitations on future borrowings, leases, hedging, and sales of assets.

As of December 31, 2023, we were in compliance with all debt covenants.

See "Note 8 – Credit Facility" to the consolidated financial statements included elsewhere in this Annual Report for additional information.

Contractual Obligations

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Total Less Than 1 Year 1-3 Years 3-5 Years More Than 5 Years

Credit facility $ 10,000 $ — $ — $ 10,000 $ —

Operating lease obligations $ 2,463 $ 655 $ 1,764 $ 44 $ —

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We have provided expanded discussion of our more significant accounting estimates below.

Please read the notes to the consolidated financial statements included elsewhere in this Annual Report for additional information regarding our accounting policies.

See "Note 2 – Summary of Significant Accounting Policies" within the consolidated financial statements included elsewhere in this Annual Report for additional information.

Use of Estimates

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There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves.

The accuracy of any reserve estimates is a function of the quality of available data and of engineering and geological interpretation

and judgment.

The accuracy of any reserve estimates is a function of the quality of available data and of engineering and geological interpretation and judgment.

As a result, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered.

Our reserve estimates are determined by an independent petroleum engineering firm.

Other items subject to significant estimates and assumptions include the carrying amount of oil and natural gas properties, valuation of commodity derivative financial instruments, determination of revenue accruals, and the determination of the fair value of equity-based awards.

We evaluate estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment.

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The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, operating costs, future capital expenditures, and a risk-adjusted discount rate.

There was a collapse in oil prices during the first quarter of 2020 due to geopolitical events that increased supply at the

same time demand weakened due to the impact of the COVID-19 pandemic.

The Partnership determined these events and

circumstances indicated a possible decline in the recoverability of the carrying value of certain proved properties and

recoverability testing determined that certain depletable units consisting of mature oil producing properties were impaired.

There was no impairment of proved oil and natural gas properties for the years ended December 31, 2023, 2022, and 2021.

We recognized $51.0 million of impairment of proved oil and natural gas properties for the year ended December 31, 2020.

Unproved properties are also assessed for impairment periodically on a depletable unit basis when facts and circumstances indicate that the carrying value may not be recoverable, at which point an impairment loss is recognized to the extent the carrying value exceeds the estimated recoverable value.

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As each unit of product represents a separate performance obligation and the consideration is variable as it relates to oil and natural gas prices, we recognize revenue from oil and natural gas sales using the practical expedient for variable consideration in ASC 606.

Lease bonus and other income

We also earn revenue from lease bonuses and delay rentals.

We generate lease bonus revenue by leasing mineral interests to exploration and production companies.

A lease agreement represents our contract with a customer and generally transfers the rights to any oil or natural gas discovered, grants us a right to a specified royalty interest, and requires that drilling and completion operations commence within a specified time period.

Control is transferred to the lessee and we have satisfied our performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received.

At the time we execute the lease agreement, we expect to receive the lease bonus payment within a reasonable time, though in no case more than one year, such that we have not adjusted the expected amount of consideration for the effects of any significant financing component per the practical expedient in ASC 606.

We also recognize revenue from delay rentals to the extent drilling has not started within the specified period, payment has been received, and we have no further obligation to refund the payment.

Allocation of transaction price to remaining performance obligations

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As we have determined that each unit of product generally represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Lease bonus and other income

Given that we do not recognize lease bonus or other income until a lease agreement has been executed, at which point its performance obligation has been satisfied, and payment is received, we do not record revenue for unsatisfied or partially unsatisfied performance obligations as of the end of the reporting period.

Prior-period performance obligations

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For the years ended December 31, 2023 and 2022, revenue recognized in the reporting periods related to performance obligations satisfied in prior reporting periods was immaterial.

Commodity Derivative Financial Instruments

Our ongoing operations expose us to changes in the market price for oil and natural gas.

To mitigate the given price risk associated with our operations, we use commodity derivative financial instruments.

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

We do not enter into derivative instruments for speculative purposes.

The impact of these derivative instruments could affect the amount of revenue we ultimately record.

Derivative instruments are recognized at fair value.

If a right of offset exists under master netting arrangements and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the consolidated balance sheets.

Gains and losses arising from changes in the fair value of derivatives are recognized on a net basis in the accompanying consolidated statements of operations within gain (loss) on commodity derivative instruments.

Although these derivative instruments may expose us to credit risk, we monitor the creditworthiness of our counterparties.

Equity-Based Compensation

We recognize equity-based compensation expense for unit-based awards granted to our employees and the Board.

Total compensation expense for unit-based awards is calculated based on the number of units multiplied by the grant-date fair value per unit.

Compensation expense for time-based restricted unit awards with graded vesting requirements are recognized using straight-line attribution over the requisite service period.

Compensation expense related to the restricted performance unit awards is determined by multiplying the number of common units underlying such awards by the measurement-date (i.e., the last day of each reporting period date) fair value and recognized using the accelerated or straight-line attribution methods, depending on the terms of the award.

Equity-based compensation expense related to unit-based awards is included in General and administrative expense within the consolidated statements of operations.

Distribution equivalent rights for the restricted performance unit awards are charged to partners’ capital.

Please read Note 9 – Incentive Compensation within the consolidated financial statements included elsewhere in this Annual Report for additional information.

New and Revised Financial Accounting Standards

The effects of new accounting pronouncements are discussed in Note 2 – Summary of Significant Accounting Policies within the consolidated financial statements included elsewhere in this Annual Report.

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

What changed 10-K

Item 7. Management’s Discussion and Analysis