What changed in this filing

/stocks — the workspaceLOADING

Item 7. Management’s Discussion and Analysis

2025-02-25 compared with 2024-02-20 · 75 added, 87 removed, 297 unchanged (35% of the section changed)

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Recent Developments

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.

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.

Development Activity

Currently, EXCO Resources, Inc.

is operating one rig and Aethon is operating three rigs on our Angelina, Nacogdoches, and San Augustine acreage in the Shelby Trough.

During 2025, Aethon has already turned-to-sales (“TTS”) 11 gross (0.9 net) wells with early data showing better performance than the older offsets and initial rates primarily between 20 – 30 MMcf/d.

We expect Aethon to continue its development program under the amended JEAs with an estimated 17 gross (1.1 net) additional wells TTS during 2025.

In the Louisiana Haynesville during 2024, we entered into several Accelerated Drilling Agreements (“ADAs”) with large, well-capitalized operators.

Under these agreements, the operators will provide near term certainty and accelerated development on our high-interest areas in exchange for a reduced royalty burden.

During 2024, 2 gross (0.4 net) wells were TTS and we expect an additional 11 gross (0.6) net wells to TTS in 2025.

In the Permian Basin, a large producer is expected to begin development of over 37 gross (1.3 net) wells in Culberson County, Texas, which includes 8 gross wells to be TTS in the fourth quarter of 2025.

Farmout Agreements

In September and December 2024, two of our farmout agreements covering non-operated working interests in San Augustine County terminated.

Consistent with our policy to minimize participation in working interests, we do not intend to step into the working interests associated with the terminated agreements.

Unless we agree otherwise with Aethon, we believe that Aethon, as operator and the party who has proposed the existing wells, has absorbed and will continue to absorb any non-consented interests.

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 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.

Oil prices rose in early 2024 due to heightened geopolitical risks, including attacks on vessels in the Red Sea and elevated tensions in the region, but declined later in the year due to market oversupply concerns.

Natural gas prices decreased sharply in late 2023 and early 2024 due to surplus storage but increased in the second quarter of 2024 due to reduced drilling and production curtailments.

This upward trend continued into the third and fourth quarters, driven by high energy demand from extreme temperatures and increased LNG exports.

Given the dynamic nature of these events, along with the geopolitical conflicts in Ukraine and the Middle East, 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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The EIA forecasts that inventories will conclude the withdrawal season, which is the end of March 2025, at 1.9 Tcf, or 1% higher than the five-year average.

The EIA expects inventories will rise to 4.0 Tcf at the end of October 2024, which would be 6% higher than the five-year average.

The EIA expects inventories will rise to 3.7 Tcf at the end of October 2025, which would be 2% lower 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

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.

Net natural gas exports averaged 12.0 Bcf per day during 2024, a 1% increase from the 2023 average.

The EIA forecasts average exports of 14.1 Bcf per day for the start of 2025, an 18% increase from 2024 levels.

The EIA forecast reflects assumptions that U.S.

LNG exports will increase as new LNG export projects begin operations in mid-2025.

How We Evaluate Our 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, 2023, we had hedged 73% of our available oil and condensate hedge volumes and 66% of our available natural gas hedge volumes for 2024.

As of December 31, 2024, we had hedged 77% and 24% of our available oil and condensate hedge volumes and 82% and 69% of our available natural gas hedge volumes for 2025 and 2026, respectively.

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

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Total revenue for the year ended December 31, 2024 decreased compared to the year ended December 31, 2023.

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.

The decrease in total revenue from the corresponding period is due to lower oil and condensate sales, lower natural gas and NGL sales, and a loss on commodity derivative instruments in 2024 compared to a gain in 2023.

Oil and condensate sales.

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.

Oil and condensate sales decreased for the year ended December 31, 2024 as compared to the year ended December 31, 2023 due to lower realized commodity prices and lower production volumes.

The decrease in oil and condensate production was driven by reduced production volumes in the Austin Chalk, Bakken/Three Forks, and Eagle Ford play trends.

Our mineral and royalty interest oil and condensate volumes accounted for 95% and 94% of total oil and condensate volumes for the years ended December 31, 2024 and 2023, respectively.

Natural gas and natural gas liquids sales.

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.

Natural gas and NGL sales decreased for the year ended December 31, 2024 as compared to the year ended December 31, 2023 due to lower realized commodity prices and lower production volumes.

The decrease in natural gas and NGL production was driven by reduced production volumes in the Austin Chalk, Bakken/Three Forks, and Haynesville/Bossier play trends.

Mineral and royalty interest production accounted for 95% and 94% of our natural gas volumes for the years ended December 31, 2024 and 2023, 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 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.

During 2024, we recognized $45.2 million of realized gains and $50.9 million of unrealized losses from our commodity derivatives, compared to $82.7 million of realized gains and $8.4 million of unrealized gains in 2023.

The unrealized losses on our commodity contracts in 2024 and the unrealized gains in 2023 were primarily driven by changes in the forward commodity price curves for 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 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.

Lease bonus and other income was slightly lower for the year ended December 31, 2024, as compared to 2023.

Leasing activity in the Wolfcamp, Bakken/Three Forks, and Austin Chalk plays made up the majority of lease bonus and other income for 2024, while the majority of our 2023 lease bonus and other income came from leasing activity in the Haynesville/Bossier and Wolfcamp plays.

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 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.

Lease operating expense decreased in 2024 as compared to 2023, due to a reduction in variable costs as a result of lower production from our non-operated working interest properties and lower nonrecurring service-related expenses, including workovers.

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, 2023, production and ad valorem taxes decreased as compared to the year ended December 31, 2022, as a result of lower commodity prices.

For the year ended December 31, 2024, production and ad valorem taxes decreased as compared to the year ended December 31, 2023, primarily due to a decrease in production taxes and processing and transportation costs stemming from lower commodity prices and decreased production volumes.

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

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

Exploration expense was higher in 2024 as compared to 2023, primarily due to an increase in seismic costs and delay rentals.

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, 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.

Depreciation, depletion, and amortization expense decreased for the year ended December 31, 2024 as compared to 2023, primarily due to lower production volumes.

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, 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.

For the year ended December 31, 2024, general and administrative expenses slightly increased compared to 2023, primarily due to increases in salaries, software related expenses, and consulting costs for internal projects;

these costs were partially offset by a decrease in equity based compensation and expenses associated with the use of contractors.

The decrease in equity-based compensation was due to lower costs recognized for performance-based incentive awards resulting from downward movements in our common unit price during 2024 compared to upward movements in our common unit price during 2023.

Other Expense

Interest expense.

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.

For the year ended December 31, 2024, interest expense increased compared to 2023, primarily due to higher average outstanding borrowings under our Credit Facility.

Liquidity and Capital Resources

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

On November 28, 2023 the distribution rate for the Series B cumulative convertible preferred units was adjusted to 9.8% and will be readjusted every two years thereafter (each, a "Readjustment Date").

The rate set on each Readjustment Date is equal to the greater of (i) the distribution rate in effect immediately prior to the relevant Readjustment Date and (ii) the 10-year Treasury Rate as of such Readjustment Date plus 5.5% per annum.

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 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.

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

As of December 31, 2024, we had not made any repurchases under the program.

Year Ended December 31, 2024 Compared to Year Ended December 31, 2023

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Cash flows provided by operating activities $ 389,043 $ 521,251 $ (132,208)

Cash flows provided by (used in) investing activities (19,740) (1,215) (18,525)

Cash flows provided by (used in) financing activities (435,536) (428,337) (7,199)

Cash flows used in investing activities (112,236) (19,740) (92,496)

Cash flows used in financing activities (344,570) (435,536) 90,966

Operating Activities .

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 2023 increased as compared to 2022.

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.

Cash provided by operating activities for 2024 decreased as compared to 2023.

The decrease was primarily due to a decrease in oil and condensate sales revenue and natural gas and NGL sales revenue, and a decrease in cash received on settlements of commodity derivative instruments.

Investing Activities .

Net cash used in investing activities for 2024 increased as compared to 2023.

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.

The change was primarily due to increased acquisition activity in 2024 compared to the same period in 2023.

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 partially offset by lower net repayments under our Credit Facility in 2023 compared with 2022.

Cash flows used in financing activities for 2024 decreased as compared to 2023.

The decrease was primarily due to lower distributions paid to common unitholders partially offset by net borrowings under our Credit Facility in 2024 compared with net repayments in 2023.

Development Capital Expenditures

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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.

Expenditures related to drilling, completion, and recompletion costs for our non-operated working interests were $0.8 million and $4.2 million during 2024 and 2023, respectively.

Additionally, we spent $3.4 million and $0.6 million acquiring leases in areas around our drilling programs during 2024 and 2023, respectively.

During 2024 we acquired mineral and royalty interests that consisted of primarily unproved oil and natural gas properties from various sellers for an aggregate of $110.4 million, including capitalized direct transaction costs.

The cash portion of the consideration paid of $109.4 million was funded with borrowings under our Credit Facility and funds from operating activities, and $1.0 million was funded through the issuance of our common units based on the fair values of the common units issued on the acquisition dates.

These acquisitions were considered asset acquisitions 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.

During 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.

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.

During 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.

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

Asset Exchange

In the third quarter of 2024, we closed on a transaction with a third-party operator whereby we received an oil and natural gas lease on approximately 8,000 net leasehold acres in East Texas in exchange for the assignment of approximately 51,000 undeveloped net mineral and royalty acres in Mississippi.

Credit Facility

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 Credit Facility has an aggregate maximum credit amount of $1.0 billion and terminates on October 31, 2027.

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.

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

The April 2023 borrowing base redetermination reaffirmed the borrowing base at $550.0 million.

The subsequent redeterminations increased the borrowing base to $580.0 million in October 2023 and reaffirmed the borrowing base in April 2024 and November 2024.

After each redetermination we elected to maintain cash commitments at $375.0 million.

The next semi-annual redetermination is scheduled for April 2025.

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

Credit facility $ 25,000 $ — $ 25,000 $ — $ —

Operating lease obligations 2,041 1,436 573 32 —

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Under this method, costs to acquire mineral and royalty interests and working interests in oil and natural gas properties, property acquisitions, successful exploratory wells, development costs, and support equipment and facilities are capitalized when incurred.

Acquisitions of proved oil and natural gas properties and working interests are generally considered business combinations and are recorded at their estimated fair value as of the acquisition date.

Acquisitions that consist of all or substantially all unproved oil and natural gas properties are generally considered asset acquisitions and are recorded at cost.

The costs of unproved leaseholds and non-producing mineral interests are capitalized as unproved properties pending the results of exploration and leasing efforts.

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

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.

The carrying value of unproved properties, including unleased mineral rights, is determined based on management’s assessment of fair value using factors similar to those previously noted for proved properties, as well as geographic and geologic data.

There was no impairment of unproved properties for the years ended December 31, 2023, 2022, and 2021.

Upon the sale of a complete depletable unit, the book value thereof, less proceeds or salvage value, is charged to income.

Upon the sale of a complete depletable unit, the book value thereof, less proceeds or salvage value, is charged to income or loss.

Upon the sale or retirement of an individual well, or an aggregation of interests which make up less than a complete depletable unit, the proceeds are credited to accumulated DD&A, unless doing so would significantly alter the DD&A rate of the depletable unit, in which case a gain or loss is recorded.

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Oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location.

The price we receive for natural gas is tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that the price of natural gas fluctuates to remain competitive with other available natural gas supplies.

The price we receive for natural gas is tied to

a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that the price of natural gas fluctuates to remain competitive with other available natural gas supplies.

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.

Allocation of transaction price to remaining performance obligations

Oil and natural gas sales

We have utilized the practical expedient in ASC 606 which states we are not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation.

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.

Prior-period performance obligations

We record oil and natural gas revenue in the month production is delivered to the purchaser.

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The difference between our estimates and the actual amounts received for oil and natural gas sales is recorded in the month that payment is received from the third party.

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.

Allocation of transaction price to remaining performance obligations

Oil and natural gas sales

New and Revised Financial Accounting Standards

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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