What changed in this filing

/stocks — the workspaceLOADING

Item 7. Management’s Discussion and Analysis

2023-02-23 compared with 2022-02-22 · 86 added, 125 removed, 351 unchanged (38% of the section changed)

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("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

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.

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, two wells are currently producing under our development agreement with Aethon, and another eight wells are being drilled or completed.

Aethon is currently drilling three wells under the separate development agreement covering San Augustine County, Texas.

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.

Austin Chalk Update

We entered into agreements with multiple operators to drill wells using advanced fracturing and completion techniques in the areas of the Austin Chalk in East Texas where we have significant acreage positions.

Five wells have been drilled and turned to sales, and another two wells are in various stages of drilling or completion under these agreements.

Early results from

these wells, while showing some variability, demonstrate that higher-intensity completions can significantly improve well performance relative to prior generation completion technology and the performance of unstimulated wells.

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.

Business Environment

The information below is designed to give a broad overview of the oil and natural gas business environment as it affects us.

COVID-19 Pandemic and Market Conditions

The COVID-19 pandemic has adversely affected the global economy, disrupted global supply chains and created significant volatility in the financial markets.

With widespread availability of vaccines, the U.S.

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

In the wake of a rise in COVID-19 cases resulting from new variants, we have maintained remote work arrangements for all employees.

Employees are allowed the flexibility of going to the office when following health and safety guidelines established by the company.

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

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

Commodity Prices and Demand

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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.

During the year ended December 31, 2021, the WTI oil spot prices ranged from a high of $85.64 per Bbl on October 26, 2021 to a low of $47.47 per Bbl on January 4, 2021.

During the year ended December 31, 2021, Henry Hub spot natural gas prices ranged from a high of $23.86 per MMBtu on February 17, 2021 to a low of $2.43 per MMBtu on April 5, 2021.

The impact of the COVID-19 pandemic has negatively affected the oil and natural gas business environment, primarily by causing a reduction in commercial activity and travel worldwide thereby lowering energy demand.

This, in turn, resulted in

periods of significantly lower market prices for oil, natural gas, and natural gas liquids.

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

The improvement in commodity prices caused many of our operators to resume their drilling and completion activity on our acreage.

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

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

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.

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

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

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

Additionally, the borrowing base under the Credit Facility takes into consideration the estimated loan value of our oil and natural gas properties.

Effective November 3, 2020, the borrowing base redetermination reduced the borrowing base from $430.0 million to $400.0 million.

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

The next borrowing base redetermination is scheduled for April 2022.

In a prolonged period of low commodity prices, we may be required to impair additional properties and the borrowing base under our Credit Facility could be further reduced.

The following table reflects commodity prices at the end of each quarter presented:

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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.

The EIA forecasts that inventories will conclude the withdrawal season, which is the end of March 2023, at 1.8 Tcf, or 16% higher than the five-year average.

The EIA expects inventories will rise to 3.7 Tcf at the end of October 2022, which would be within 1% of the five-year average.

The EIA expects inventories will rise to 3.8 Tcf at the end of October 2023, which would be 5% higher than the five-year average.

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

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Natural Gas Exports

Rising levels of U.S.

natural gas exports have been a growing source of demand, particularly in the Gulf Coast region where the majority of our natural gas is produced.

The EIA expects natural gas exports will reach record highs in 2022 and continue to grow in 2023 due to a combination of both rising LNG exports and increases in pipeline exports to Mexico.

Net natural gas exports averaged 10.7 Bcf per day in 2021 and the EIA forecasts that they will increase to 13.4 Bcf per day in 2022 and 14.3 Bcf per day in 2023.

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.

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 rise in LNG exports from the United States has increased demand for domestic natural gas production and had a positive impact on natural gas prices.

The EIA expects high levels of U.S.

LNG exports to continue into 2022, averaging 16% above 2021 levels.

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

LNG export capacity comes online.

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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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 December 31, 2021, we had hedged 63% of our available oil and condensate hedge volumes for 2022 and 65% and 14% of our available natural gas hedge volumes for 2022 and 2023, respectively.

As of December 31, 2022, we had hedged 81% of our available oil and condensate hedge volumes and 68% of our available natural gas hedge volumes for 2023.

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

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

We define Distributable cash flow as Adjusted EBITDA plus or minus amounts for certain non-cash operating activities, cash interest expense, distributions to noncontrolling interests and preferred unitholders, and restructuring charges.

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

We define Distributable cash flow as Adjusted EBITDA plus or minus amounts for certain non-cash operating activities, cash interest expense, distributions to preferred unitholders, and restructuring charges, if any.

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

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Depreciation, depletion, and amortization 47,804 61,019

Impairment of oil and natural gas properties — 51,031

Interest expense 6,286 5,638

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Preferred unit distributions (21,000) (21,000)

Restructuring charges — 4,815

Distributable cash flow $ 441,062 $ 267,401

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Revenue from contracts with customers 784,284 505,734 278,550 55.1 %

Gain (loss) on commodity derivative instruments (146,474) 46,111 (192,585) NM 2

Gain (loss) on commodity derivative instruments (120,680) (146,474) 25,794 (17.6) %

Total revenue $ 663,604 $ 359,260 $ 304,344 84.7 %

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Depreciation, depletion, and amortization 47,804 61,019 (13,215) (21.7) %

Impairment of oil and natural gas properties — 51,031 (51,031) (100.0) %

General and administrative 53,652 48,746 4,906 10.1 %

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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.

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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 an increase in oil and condensate sales, natural gas and NGL sales, and lease bonus and other income.

The overall increase was partially offset by a loss on commodity derivative instruments in 2021 compared to a gain in 2020.

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.

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 Permian Basin and Eagle Ford.

The decrease in Permian Basin production was driven by divestitures of certain Permian Basin mineral and royalty properties in the third quarter of 2020 and the decrease in Eagle Ford production was driven by normal production declines with less new development activity.

Our mineral and royalty interest oil and condensate volumes accounted for 93% and 92% of total oil and condensate volumes for the years ended December 31, 2021 and 2020, respectively.

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.

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 Haynesville/Bossier play.

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

Mineral and royalty interest production accounted for 92% and 84% of our natural gas volumes for the years ended December 31, 2022 and 2021, respectively.

Gain (loss) on commodity derivative instruments.

During 2021, we recognized a loss from our commodity derivative instruments compared to a gain in 2020.

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.

During 2021, we recognized $112.9 million of realized losses and $33.5 million of unrealized losses from our commodity derivatives, compared to $81.3 million of realized gains and $35.2 million of unrealized losses in 2020.

The unrealized losses on our commodity contracts in 2021 and 2020 were both primarily driven by changes in the forward commodity price curves for oil and natural gas.

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.

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 higher for the year ended December 31, 2021, as compared to the same period in 2020.

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

Leasing activity in the Permian Basin, Haynesville/Bossier, Green River Basin, and Bakken/Three Forks plays, as well as certain surface leases in Polk County, Texas made up the majority of lease bonus and other income in 2020.

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.

Operating Expenses

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

For the year ended December 31, 2021, production and ad valorem taxes increased as compared to the year ended December 31, 2020, as a result of higher commodity prices partially offset by lower ad valorem tax estimates.

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.

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

Exploration expense for 2022 was minimal.

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

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, 2021 as compared to 2020, primarily due to lower production volumes and a reduction in cost basis with lower

corresponding reduction in proved developed producing reserve quantities.

The reduction in cost basis is primarily due to oil and natural gas property divestitures in the third quarter of 2020, and continued depreciation, depletion, and amortization.

Impairment of oil and natural gas properties.

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

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

There was no impairment for December 31, 2021.

There was $51.0 million in impairment for 2020 primarily due to declines in future expected realizable net cash flows as a result of lower commodity prices as of the measurement date of March 31, 2020.

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.

General and administrative.

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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 2021 compared to downward movements in our common unit price in 2020.

The overall increase was partially offset by charges recognized in 2020 that did not recur.

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

The increase in

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

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

Other Expense

Interest expense.

For the year ended December 31, 2021, interest expense decreased compared to 2020, primarily due to lower average outstanding borrowings partially offset by higher interest rates under our Credit Facility.

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

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, 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.

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).

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

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.

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.

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

Cash provided by operating activities for 2021 decreased as compared to 2020.

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

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

Cash provided by operating activities for 2022 increased as compared to 2021.

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.

Investing Activities .

Net cash was used in investing activities for 2021 as compared to net cash being provided by investing activities for 2020.

The change was primarily due to cash paid for acquisitions of oil and natural gas properties in 2021 compared to proceeds from the sale of oil and natural gas properties in 2020.

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.

Financing Activities .

Cash flows used in financing activities for 2021 decreased as compared to 2020.

The decrease was primarily due to lower net repayments under our Credit Facility in 2021 compared with 2020.

The overall decrease was partially offset by higher distributions paid to common unitholders.

Cash flows used in financing activities for 2022 increased as compared to 2021.

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.

Development Capital Expenditures

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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 for workovers and recompletions on existing wells in which we own a working interest.

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.

We spent approximately $0.6 million and $4.2 million associated with our non-operated working interests, net of farmout reimbursements during 2022 and 2021, respectively.

We had no material acquisition activity during 2022.

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

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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.

We had no acquisition activity during 2020.

During 2019 we spent approximately $43.1 million and issued common units valued at $0.9 million related to acquisitions of mineral and royalty interests, which also included proved oil and natural gas properties.

See Note 4 – Oil and Natural Gas Properties to the consolidated financial statements included elsewhere in this Annual Report for additional information.

Credit Facility

Pursuant to our $1.0 billion senior secured revolving credit agreement, as amended (the "Credit Facility"), the commitment of the lenders equals the lesser of the aggregate maximum credit amounts of the lenders and the borrowing base, which is determined based on the lenders’ estimated value of our oil and natural gas properties.

Borrowings under the Credit Facility may be used for the acquisition of properties, cash distributions, and other general corporate purposes.

Our Credit Facility terminates on November 1, 2024.

As of December 31, 2021, we had outstanding borrowings of $89.0 million at a weighted-average interest rate of 2.61%.

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.

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

In addition, we and the lenders (at the election of two-thirds of the lenders) each have discretion to have the borrowing base redetermined once between scheduled redeterminations.

We maintain a senior secured revolving credit agreement, as amended, (the “Credit Facility”).

The Credit Facility has an aggregate maximum credit amount of $1.0 billion.

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.

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

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

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 next semi-annual redetermination is scheduled for April 2023.

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.

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

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 LIBOR breakage, and is required to be paid (a) if the amount outstanding exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise, in some cases subject to a cure period, or (b) at the maturity date.

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.

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As of December 31, 2022, we were in compliance with all debt covenants.

On March 5, 2021, the U.K.

Financial Conduct Authority announced that it intends to stop persuading or compelling banks

to submit LIBOR rates after December 31, 2021 for the 1-week and 2-month U.S.

dollar settings and after June 30, 2023 for the

remaining U.S.

dollar settings.

Our Credit Facility includes provisions to determine a replacement rate for LIBOR if necessary

during its term, based on the secured overnight financing rate published by the Federal Reserve Bank of New York (“SOFR”).

We currently do not expect the transition from LIBOR to have a material impact on us.

Contractual Obligations

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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.

26 unchanged sentences

This evaluation is performed on a depletable unit basis.

We compare the undiscounted projected future cash flows expected in connection with a depletable unit to its unamortized carrying amount to

determine recoverability.

We compare the undiscounted projected future cash flows expected in connection with a depletable unit to its unamortized carrying amount to determine recoverability.

When the carrying amount of a depletable unit exceeds its estimated undiscounted future cash flows, the carrying amount is written down to its fair value, which is measured as the present value of the projected future cash flows of such properties.

54 unchanged sentences

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 expected to vest multiplied by the grant-date fair value per unit.

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 that, based on our estimate, are probable to vest, 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.

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 that are expected to vest are charged to partners’ capital.

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.

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