TXO Partners LP
For the period ended Dec 31, 2024. Filed Mar 4, 2025.
View on SEC.govAbout this filing
A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2024 · Filed Mar 4, 2025
TXO$13.13+3.5%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-K
Period ended 2023-12-31; filed 2024-03-05.
0001559432-24-000011
Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-K
Period ended 2024-12-31; filed 2025-03-04.
0001559432-25-000035
Item 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 155 previous paragraphs and 153 current paragraphs.
97 unchanged; 44 reworded; 11 added; 9 removed; 5 previous and 1 current paragraphs rearranged.
Tables are not compared: 14 previous and 12 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (11)
Current report
Recent Developments
Current report
Mancos Shale Development
Current report
The Mancos Shale is a large natural gas field, located in the San Juan Basin, where we hold an approximately 58,500 contiguous-acre position that is held by production. We have identified a 3,500-acre block as Phase I for developing and monetizing reserves, representing approximately 6% of our current Mancos position. Since our position is not subject to any leasehold expiration dates, we expect to develop this acreage at a measured pace as commodity prices allow. As of December 31, 2024, we do not have any proved reserves associated with our current Mancos position. Please see “Risk Factors—Risks Related to Our Business and the Oil, Natural Gas and NGL Industry—Reserve estimates depend on many assumptions that may ultimately be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.”
Current report
Equity Offering
Current report
On June 28, 2024, we completed the Offering for the sale of 6.5 million common units at a price of $20.00 per common unit, which resulted in proceeds of $122.5 million net of underwriting discounts, commissions and other costs. On July 2, 2024, we completed the sale of an additional 975,000 common units at a price of $20.00 per common unit pursuant to the underwriter’s exercise in full of its option to purchase additional common units in the Offering, resulting in additional proceeds of $18.7 million net of underwriting discounts, commissions and other costs. We used the net proceeds from the Offering to fund a portion of the cash consideration for the Williston Acquisitions.
Current report
Results of Operations
Current report
Williston Basin acquisitions. This increase was partially offset by decreased maintenance and energy costs on our historical properties.
Current report
Interest expense increased $3.5 million, or 78%, from $4.4 million for the year ended December 31, 2023 to $7.9 million for the year ended December 31, 2024. The increase is primarily attributable to increased borrowings due tothe Williston Basin acquisitions and a higher interest rate.
Current report
On June 28, 2024, we completed the Offering for the sale of 6.5 million common units at a price of $20.00 per common unit which resulted in proceeds of $122.5 million net of underwriting discounts, commissions and other costs. On July 2, 2024, we completed the sale of an additional 975,000 common units at a price of $20.00 per common unit pursuant to the underwriter’s exercise in full of its option to purchase additional common units in the Offering, resulting in additional proceeds of $18.7 million net of underwriting discounts, commissions and other costs. We used the net proceeds from the Offering to fund a portion of the cash consideration for the Williston Acquisitions.
Current report
Our net credit facility debt as of December 31, 2024 was $142.7 million (less cash of $7.3 million). These borrowings under our Credit Facility, which increased our net debt-to-EBITDAX ratio to approximately one times, were incurred to fund the remainder of the Williston Basin Acquisitions. We expect to carry this level of debt moving forward.
Current report
Net cash provided by (used by) financing activities
Removed paragraphs (9)
Previous report
Initial Public Offering
Previous report
On January 31, 2023, we completed our initial public offering in which we issued and sold 5,000,000 common units at a public offering price of $20.00 per unit. In addition, on February 6, 2023, we sold an additional 750,000 common units pursuant to the underwriter’s option to purchase additional units to cover over-allotments. We received net proceeds of approximately $102.0 million, after deducting underwriting discounts and commissions and offering expenses borne by us. We utilized the proceeds from our initial public offering and cash on hand to pay down our credit facility.
Previous report
For additional information, see Note 1 to our audited consolidated financial statements in this Annual Report on Form 10-K.
Previous report
Interest expense decreased $3.8 million, or 46%, from $8.2 million for the year ended December 31, 2022 to $4.4 million for the year ended December 31, 2023. The decrease is primarily attributable to the decreased borrowings due in part to the January 2023 initial public offering partially offset by a higher interest rate and increased commitment fees.
Previous report
Our net credit facility debt as of December 31, 2023 was $16.5 million (less cash of $4.5 million) and was incurred to cover our acquisition and capital expenditures for other property of $10.3 million as well as the change in the capital accrual during the year ended December 31, 2023 of $6.0 million. We expect to repay the debt incurred by us to complete such acquisition and capital expenditures in order to meet our long-term goal of remaining substantially debt free.
Previous report
Revenue recognition
Previous report
Oil, NGL and natural gas revenues are recognized upon the satisfaction of the performance obligation which occurs at the point in time when control of the product transfers to a customer, in an amount that reflects the consideration to which we expect to be entitled in exchange for the product.
Previous report
Recent accounting pronouncements
Previous report
A summary of recent accounting pronouncements and our assessment of any expected impact of these pronouncements if known is included in Note 1 to the audited consolidated financial statements.
Reworded paragraphs (44)
Previous wording
We are an independent oil and natural gas company focused on the acquisition, development, optimization and exploitation of conventional oil, natural gas and natural gas liquid reserves in North America. Our properties are predominately located in the Permian Basin of New Mexico and Texas and the San Juan Basin of New Mexico and Colorado.
Current wording
We are an independent oil and natural gas company focused on the acquisition, development, optimization and exploitation of conventional oil, natural gas and natural gas liquid reserves in North America. Our properties are predominately located in the Permian Basin of New Mexico and Texas, the San Juan Basin of New Mexico and Colorado and the Williston Basin of Montana and North Dakota.
Previous wording
The oil and natural gas industry is cyclical and commodity prices are highly volatile. For example, during the period from January 1, 2021 through December 31, 2023, prices for crude oil and natural gas reached a high of $123.70 per Bbl and $9.68 per MMBtu, respectively, and a low of $47.62 per Bbl and $1.99 per MMBtu, respectively. Oil prices steadily increased through 2021 due to continued recovery in demand before increasing drastically in the first half of 2022 due to further demand, domestic supply reductions, OPEC control measures and market disruptions resulting from the Russia-Ukraine war and sanctions on Russia. Oil prices moderated over the second half of 2022 and the first half of 2023 before initially increasing in the second half of 2023 as a result of expected supply constraints and hostilities in the Middle East. Since these concerns did not materialize, oil prices declined in the last month of 2023 and first month of 2024 declining to $77.82 per Bbl as of January 30, 2024. Natural gas prices reached a high of $9.68 per MMbtu in August 2022 before declining to $2.08 per MMbtu as of January 30, 2024. These prices have been very volatile and experience large swings, sometimes on a day-to-day or week-to-week basis.
Current wording
The oil and natural gas industry is cyclical and commodity prices are highly volatile. For example, during the period from January 1, 2022 through December 31, 2024, prices for crude oil and natural gas reached a high of $123.70 per Bbl and $9.68 per MMBtu, respectively, and a low of $65.75 per Bbl and $1.58 per MMBtu, respectively. Oil prices increased drastically in the first half of 2022 due to demand, domestic supply reductions, OPEC control measures and market disruptions resulting from the Russia-Ukraine war and sanctions on Russia. Oil prices moderated over the second half of 2022 and the first half of 2023 before initially increasing in the second half of 2023 as a result of expected supply constraints and hostilities in the Middle East. Since these concerns did not materialize, oil prices declined in December 2023 but continuing hostilities and higher global consumption pushed prices higher in the first half of 2024. However, increased supply led to lower prices in the second half of 2024 declining to $72.73 per Bbl as of January 30, 2025. Natural gas prices reached a high of $9.68 per MMbtu in August 2022 before declining to $1.58 per MMBtu in February 2024 and then rebounding to $3.05 per MMbtu as of January 30, 2025. These prices have been very volatile and experience large swings, sometimes on a day-to-day or week-to-week basis.
Previous wording
With our anticipated cash flows from our long-lived property base, we intend to provide dynamic allocation of funds to prudently meet our goals. These goals include the highest projected economic returns on our capital budget, acquisition opportunities that fulfill our strategy, and cash distributions for the life of our legacy assets. From time to time, we may choose to amortize the repayment of debt incurred in modest acquisitions to support the longer-term financial stewardship of our business. At other times, given fluctuations in industry costs and commodity prices, we may modify our capital budget or cash balances to shift funds towards cash distributions. We will use all of these tools to support our underlying strategy as a “production and distribution” enterprise.
Current wording
With our anticipated cash flows from our long-lived property base, we intend to provide dynamic allocation of funds to prudently meet our goals. These goals include the highest projected economic returns on our capital budget, acquisition opportunities that fulfill our strategy, and cash distributions for the life of our legacy assets. From time to time, we may choose to prioritize the repayment of debt incurred in acquisitions to support the longer-term financial stewardship of our business. At other times, given fluctuations in industry costs and commodity prices, we may modify our capital budget or cash balances to shift funds towards cash distributions. We will use all of these tools to support our underlying strategy as a “production and distribution” enterprise.
Previous wording
Concerns over global economic conditions, energy costs, supply chain disruptions, increased demand, labor shortages associated with a fully employed U.S. labor force, geopolitical issues, inflation, the availability and cost of credit and the United States financial market and other factors have contributed to increased economic uncertainty and diminished expectations for the global economy. During the year ended December 31, 2022, the U.S. economy experienced the highest rate of inflation in the past 40 years. Rising inflation has been pervasive since 2022, increasing the cost of salaries, wages, supplies, material, freight, and energy. We expect relatively higher inflation to continue in 2024 resulting in higher costs. Though we incorporated inflationary factors into our 2024 business plan, inflation may outpace those assumptions. We continue to undertake actions and implement plans to strengthen our supply chain to address these pressures and protect the requisite access to commodities and services. Nevertheless, we expect for the foreseeable future to experience supply chain constraints and inflationary pressure on our cost structure. Principally, commodity costs for steel and chemicals required for drilling, higher transportation and fuel costs and wage increases have increased our operating costs for the year ended December 31, 2023 compared to the year ended December 31, 2022. While prices appear to have stopped increasing as rapidly, we do not expect these cost increases to reverse in the short term. Typically, as prices for oil and natural gas increase, so do associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion to prices. We cannot predict the future inflation rate but to the extent these higher costs do not begin to reverse or start to increase again, we may experience a higher cost environment going forward. If we are unable to recover higher costs through higher commodity prices, our current revenue stream, estimates of future reserves, borrowing base calculations, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions would all be significantly impacted.
Current wording
Concerns over global economic conditions, energy costs, supply chain disruptions, increased demand, labor shortages associated with a fully employed U.S. labor force, geopolitical issues, inflation, the availability and cost of credit and the United States financial markets and other factors have contributed to increased economic uncertainty and diminished expectations for the global economy. During the year ended December 31, 2022, the U.S. economy experienced the highest rate of inflation in the past 40 years. Rising inflation has been pervasive since 2022, increasing the cost of salaries, wages, supplies, material, freight, and energy. While we have seen inflation moderate in 2024, inflation continues to run higher than the Federal Reserve target, resulting in higher costs. We continue to undertake actions and implement plans to address these pressures and protect the requisite access to commodities and services, however, these mitigation efforts may not succeed or be insufficient. Nevertheless, we expect for the foreseeable future to experience inflationary pressure on our cost structure. Principally, commodity costs for steel and chemicals required for drilling, higher transportation and fuel costs and wage increases have increased our operating costs. We do not expect these cost increases to reverse in the short term. Typically, as prices for oil and natural gas increase, so do associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion to prices. We cannot predict the future inflation rate but to the extent these higher costs do not begin to reverse or start to increase again, we may experience a higher cost environment going forward. If we are unable to recover higher costs through higher commodity prices, our current revenue stream, estimates of future reserves, borrowing base calculations, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions would all be significantly impacted.
Previous wording
Our results of operations depend on many factors, particularly the price of our commodity production and our ability to market our production effectively. Oil and natural gas prices have historically been volatile. During the period from January 1, 2021 through December 31, 2023, prices for crude oil and natural gas reached a high of $123.70 per Bbl and $9.68 per MMBtu, respectively, and a low of $47.62 per Bbl and $1.99 per MMBtu, respectively. A future decline in commodity prices may adversely affect our business, financial condition or results of operations. Lower commodity prices may not only decrease our revenues, but also the amount of oil and natural gas that we can produce economically. Lower oil and natural gas prices may also result in a reduction in the borrowing base under our Credit Facility, which is redetermined semi-annually. See “—Liquidity and Capital Resources—Revolving credit agreement.”
Current wording
Our results of operations depend on many factors, particularly the price of our commodity production and our ability to market our production effectively. Oil and natural gas prices have historically been volatile. During the period from January 1, 2022 through December 31, 2024, prices for crude oil and natural gas reached a high of $123.70 per Bbl and $9.68 per MMBtu, respectively, and a low of $65.75 per Bbl and $1.58 per MMBtu, respectively. A future decline in commodity prices may adversely affect our business, financial condition or results of operations. Lower commodity prices may not only decrease our revenues, but also the amount of oil and natural gas that we can produce economically. Lower oil and natural gas prices may also result in a reduction in the borrowing base under our Credit Facility, which is redetermined semi-annually. See “—Liquidity and Capital Resources—Revolving credit agreement.”
Previous wording
The NYMEX WTI, for oil prices, and NYMEX Henry Hub, for gas prices, are widely used benchmarks for the pricing of oil and natural gas in the United States. The price we receive for our oil and natural gas production is generally different than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors. For example, most of our gas is sold in the San Juan Basin. As such, our revenues are sensitive to the price of the underlying commodity to which they relate. The following is a comparison of average pricing excluding and including the effects of derivatives:
Current wording
The NYMEX WTI, for oil prices, and NYMEX Henry Hub, for gas prices, are widely used benchmarks for the pricing of oil and natural gas in the United States. The price we receive for our oil and natural gas production is generally different than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors. For example, most of our gas is sold at the San Juan basis. As such, our revenues are sensitive to the price of the underlying commodity to which they relate. The following is a comparison of average pricing excluding and including the effects of derivatives:
Previous wording
The price we receive for our oil and natural gas production is generally less than the NYMEX prices because of adjustments for basis, relative quality and other factors. We have entered into basis swap agreements that effectively fix the basis adjustment for our delivery locations.
Current wording
The price we receive for our oil and natural gas production is generally less than the NYMEX prices because of adjustments for basis, relative quality and other factors. We have entered into basis swap agreements for a portion of our gas production that effectively fix the basis adjustment for our delivery locations.
Previous wording
In the year ended December 31, 2023, all of our hedging activities increased oil revenue $2.3 million, NGL revenue $1.4 million and gas revenue $19.4 million. In the year ended December 31, 2022, all of our hedging activities decreased oil revenue $45.8 million, NGL revenue $5.6 million and gas revenue $151.8 million. In the year ended December 31, 2021, all of our hedging activities increased oil revenue $0.3 million, NGL revenue $0.5 million and gas revenue $8.2 million.
Current wording
In the year ended December 31, 2024, all of our hedging activities increased oil revenue $0.2 million and decreased NGL revenue $0.0 million and gas revenue $2.8 million. In the year ended December 31, 2023, all of our hedging activities increased oil revenue $2.3 million, NGL revenue $1.4 million and gas revenue $19.4 million. In the year ended December 31, 2022, all of our hedging activities decreased oil revenue $45.8 million, NGL revenue $5.6 million and gas revenue $151.8 million.
Previous wording
Texas does not currently impose a personal income tax on individuals, but it does impose an entity level tax (to which we will be subject) on corporations and other entities. While we do not pay income tax in Texas, we are subject to Texas franchise taxes.
Current wording
Texas does not currently impose a personal income tax on individuals, but it does impose an entity level tax (to which we are subject) on corporations and other entities. While we do not pay income tax in Texas, we are subject to Texas franchise taxes.
Previous wording
Although we have not quantified cash available for distribution on a historical basis, we intend to use cash available for distribution to assess our ability to internally fund our exploration and development activities, pay distributions, and to service or incur additional debt. We define cash available for distribution as Adjusted EBITDAX less cash interest expense, exploration expense and development costs. Development costs include all of our capital expenditures made for oil and gas properties, other than acquisitions. Cash available for distribution will not reflect changes in working capital balances.
Current wording
We use cash available for distribution to assess our ability to internally fund our exploration and development activities, pay distributions, and to service or incur additional debt. We define cash available for distribution as Adjusted EBITDAX less cash interest expense, exploration expense and development costs. Development costs include all of our capital expenditures made for oil and gas properties, other than acquisitions. Cash available for distribution will not reflect changes in working capital balances.
Previous wording
(1)Oil and condensate prices include both realized and unrealized losses from derivatives. The unrealized gains were $9.5 million for the year ended December 31, 2023, unrealized losses were $13.0 million for the year ended December 31, 2022 and unrealized gains were $0.3 million for the year ended December 31, 2021. The realized losses were $7.1 million for the year ended December 31, 2023, $32.8 million for the year ended December 31, 2022 and $0.0 million for the year ended December 31, 2021.
Current wording
(1)Oil and condensate prices include both realized and unrealized losses from derivatives. The unrealized gains were $5.8 million for the year ended December 31, 2024 and $9.5 million for the year ended December 31, 2023 and unrealized losses were $13.0 million for the year ended December 31, 2022. The realized losses were $5.6 million for the year ended December 31, 2024, $7.1 million for the year ended December 31, 2023 and $32.8 million for the year ended December 31, 2022.
Previous wording
(2)Natural gas liquids prices include both realized and unrealized losses from derivatives. The unrealized gains were $1.0 million for the year ended December 31, 2023, unrealized losses were $1.0 million for the year ended December 31, 2022 and unrealized gains were $0.5 million for the year ended December 31, 2021. The realized gains were $0.4 million for the year ended December 31, 2023, realized losses were $4.6 million for the year ended December 31, 2022 and $0.0 million for the year ended December 31, 2021.
Current wording
(2)Natural gas liquids prices include both realized and unrealized losses from derivatives. The unrealized losses were $0.5 million for the year ended December 31, 2024, unrealized gains were $1.0 million for the year ended December 31, 2023 and unrealized losses were $1.0 million for the year ended December 31, 2022. The realized gains were $0.5 million for the year ended December 31, 2024 and $0.4 million for the year ended December 31, 2023 and realized losses were $4.6 million for the year ended December 31, 2022.
Previous wording
(3)Natural gas prices include both realized and unrealized losses from derivatives. The unrealized gains were $95.8 million for the year ended December 31, 2023, unrealized gains losses $99.2 million for the year ended December 31, 2022 and unrealized gains were $8.2 million for the year ended December 31, 2021. The realized losses were $76.4 million for the year ended December 31, 2023 and $52.6 million for the year ended December 31, 2022 and $0.0 million for the year ended December 31, 2021.
Current wording
(3)Natural gas prices include both realized and unrealized losses from derivatives. The unrealized losses were $12.8 million for the year ended December 31, 2024, unrealized gains were $95.8 million for the year ended December 31, 2023 and unrealized losses were $99.2 million for the year ended December 31, 2022. The realized gains were $10.0 million for the year ended December 31, 2024 and realized losses were $76.4 million for the year ended December 31, 2023 and $52.6 million for the year ended December 31, 2022.
Previous wording
Revenues increased $134.3 million, or 55%, from $246.4 million for the year ended December 31, 2022 to $380.7 million for the year ended December 31, 2023. The increase was primarily attributable to net gains on our hedging activity of $226.4 million, of which $219.5 million were unrealized gains and $6.9 million were related to lower realized losses. Additionally, revenue increased $6.3 million in spite of a decrease in production of 69 MBoe primarily as a result of the acquisition of additional interest in the Permian Basin being offset by natural declines in San Juan Basin. These increases were partially offset by a decrease in the average selling price, excluding the effects of derivatives, on oil of 19%, resulting in a decrease in revenue of $39.2 million, on NGLs of 36%, resulting in a decrease in revenue of $17.3 million and on gas of 21%, resulting in a decrease in revenue of $42.0 million.
Current wording
Revenues decreased $97.9 million, or 26%, from $380.7 million for the year ended December 31, 2023 to $282.8 million for the year ended December 31, 2024. The decrease was primarily attributable to a decrease in the average selling price, excluding the effects of derivatives, on oil of 4%, resulted in a decrease in revenue of $7.2 million and on gas of 60%, resulted in a decrease in revenue of $89.5 million. Additionally, net losses on our hedging activity of $25.7 million, of which $113.6 million were related to increased unrealized losses partially offset by $87.9 million related to lower realized losses. These decreases were partially offset by an increase in production of 162 MBoe which resulted in increased revenue of $22.4 million primarily as a result of the acquisition of producing assets in the Williston Basin being offset by natural declines in San Juan Basin and an increase in the average selling price, excluding the effects of derivatives, on NGLs of 8%, resulting in an increase in revenue of $2.2 million.
Previous wording
Production expenses increased $17.1 million, or 13%, from $127.7 million for the year ended December 31, 2022 to $144.7 million for the year ended December 31, 2023. Of this increase, $4.1 million is attributable to the acquisition of additional interest in the Permian Basin. The remainder of the increase is primarily due to increased maintenance and energy costs.
Current wording
Production expenses increased $5.6 million, or 4%, from $144.7 million for the year ended December 31, 2023 to $150.3 million for the year ended December 31, 2024. Of this increase, $10.0 million is attributable to production fromthe
Previous wording
On a per unit basis, production expenses increased from $15.08 per Boe sold for the year ended December 31, 2022 to $17.24 per Boe sold for the year ended December 31, 2023. The increase is primarily related to the increased costs per Boe from the acquisition of additional interest in the Permian Basin due to the acquired properties having a higher percentage of oil production, which is more expensive on a Boe basis than natural gas production. Additionally, increased maintenance and energy costs contributed to the increase per Boe.
Current wording
On a per unit basis, production expenses increased from $17.24 per Boe sold for the year ended December 31, 2023 to $17.56 per Boe sold for the year ended December 31, 2024. The increase is primarily related to the increased costs per Boe from our historical properties as decreased production more than offset decreased costs in these properties. This increase was partially offset by lower costs per Boe fromthe Williston Basin acquisitions.
Previous wording
Taxes, transportation, and other decreased $19.6 million, or 21%, from $95.0 million for the year ended December 31, 2022 to $75.4 million for the year ended December 31, 2023. The decrease is primarily attributable to the decrease in oil, NGLs and natural gas prices as well as decreased NGLs and natural gas volumes.
Current wording
Taxes, transportation, and other decreased $15.0 million, or 20%, from $75.4 million for the year ended December 31, 2023 to $60.4 million for the year ended December 31, 2024. The decrease is primarily attributable to the decrease in oil, NGLs and natural gas prices as well as decreased NGLs and natural gas volumes.
Previous wording
On a per unit basis, taxes, transportation, and other decreased from $11.22 per Boe sold for the year ended December 31, 2022 to $8.98 per Boe sold for the year ended December 31, 2023. The decrease is primarily attributable to the decrease in oil, NGLs and natural gas prices.
Current wording
On a per unit basis, taxes, transportation, and other decreased from $8.98 per Boe sold for the year ended December 31, 2023 to $7.06 per Boe sold for the year ended December 31, 2024. The decrease is primarily attributable to the decrease in oil, NGLs and natural gas prices.
Previous wording
Depreciation, depletion, and amortization increased $2.9 million, or 7%, from $41.4 million for the year ended December 31, 2022 to $44.3 million for the year ended December 31, 2023. The increase is primarily attributable to the increased production associated with the acquisition of additional interest in the Permian Basin in the third quarter of 2022 of $3.0 million.
Current wording
Depreciation, depletion, and amortization increased $8.1 million, or 18%, from $44.3 million for the year ended December 31, 2023 to $52.4 million for the year ended December 31, 2024. The increase is primarily attributable to the increased production associated withthe Williston Basin acquisitions of $10.4 million which has a higher rate than the historical properties, partially offset by decreased production on our historical properties.
Previous wording
On a per unit basis, depreciation, depletion, and amortization increased from $4.89 per Boe sold for the year ended December 31, 2022 to $5.27 per Boe sold for the year ended December 31, 2023. The increase is primarily related to changes in production mix.
Current wording
On a per unit basis, depreciation, depletion, and amortization increased from $5.27 per Boe sold for the year ended December 31, 2023 to $6.12 per Boe sold for the year ended December 31, 2024. The increase is primarily related to the production associated withthe Williston Basin acquisitions which has a higher rate than the historical properties.
Previous wording
We recorded an impairment of long-lived assets of $223.4 million for the year ended December 31, 2023. The impairment is related toour assets in the Texas Permian Basin, that is within our Cross Timbers joint venture, primarily due to a lower net commodity price environment and higher costs as well as a change in our development plans to reduce the duration of the proved undeveloped reserves from five years to two years. We did not recognize an impairment of long-lived assets during the year ended December 31, 2022.
Current wording
We did not record an impairment of long-lived assets for the year ended December 31, 2024. We recorded an impairment of long-lived assets of$223.4 million for the year ended December 31, 2023. The impairment was related toour assets in the Texas Permian Basin, that is within our Cross Timbers joint venture, primarily due to a lower net commodity price environment and higher costs as well as a change in our development plans to reduce the duration of the proved undeveloped reserves from five years to two years.
Previous wording
General and administrative (“G&A”) expenses increased $6.2 million, or 379%, from $1.6 million for the year ended December 31, 2022 to $7.9 million for the year ended December 31, 2023. The increase is primarily attributable to higher personnel costs of $4.2 million due in part to amortization of unit awards and additional expenses related to the initial public offering in January 2023.
Current wording
General and administrative (“G&A”) expenses increased $6.6 million, or 84%, from $7.9 million for the year ended December 31, 2023 to $14.5 million for the year ended December 31, 2024. The increase is primarily attributable to higher personnel costs of $4.8 million due in part to amortization of unit awards and additional expenses related to being a public company.
Previous wording
On a per unit basis, G&A expense increased from $0.19 per Boe sold for the year ended December 31, 2022 to $0.94 per Boe sold for the year ended December 31, 2023. The increase is primarily related to increased costs and decreased production.
Current wording
On a per unit basis, G&A expense increased from $0.94 per Boe sold for the year ended December 31, 2023 to $1.70 per Boe sold for the year ended December 31, 2024. The increase is primarily related to increased costs partially offset by increased production.
Previous wording
Other income decreased $2.3 million, or 9%, from $26.1 million for the year ended December 31, 2022 to $23.8 million for the year ended December 31, 2023. The decrease is primarily attributable to lower CO 2 and plant income of $1.4 million related to plant downtime as well as a $0.8 million decline in our gas marketing income. The plant came back online in late December 2023. The CO 2 and plant income is ancillary to the operations of the Vacuum properties.
Current wording
Other income increased $13.4 million, or 56%, from $23.8 million for the year ended December 31, 2023 to $37.2 million for the year ended December 31, 2024. The increase is primarily attributable to$9.7 millionin bonus receipts on term assignment of leases, higher CO 2 and plant income of$3.1 million and a$0.7 million increase in marketing income. The CO 2 and plant income is ancillary to the operations of the gas processing plant in the Permian Basin in New Mexico and CO 2 assets in Colorado.
Previous wording
Our primary sources of liquidity and capital are cash flows generated by operating activities and borrowings under our Credit Facility. Outstanding borrowings under our Credit Facility were $21.0 million at December 31, 2023 and $113.0 million at December 31, 2022, and the remaining availability under our Credit Facility was $144.0 million at December 31, 2023 and $52.0 million at December 31, 2022. Additionally, we had positive net working capital (including cash and excluding the effects of derivative instruments) of $14.1 million at December 31, 2023 and $20.7 million at December 31, 2022.
Current wording
Our primary sources of liquidity and capital are cash flows generated by operating activities and borrowings under our Credit Facility. Outstanding borrowings under our Credit Facility were $150.0 million at December 31, 2024 and $21.0 million at December 31, 2023, and the remaining availability under our Credit Facility was $125.0 million at December 31, 2024 and $144.0 million at December 31, 2023. Additionally, we had negative net working capital (including cash and excluding the effects of derivative instruments) of $2.5 million at December 31, 2024 and positive net working capital of $14.1 million at December 31, 2023.
Previous wording
As a publicly traded partnership, our primary sources of liquidity and capital resources are from cash flow generated by operating activities and borrowings under our Credit Facility. Historically, our primary sources of liquidity have also included capital contributions by our equity holders, but we do not expect to rely on management or our partners for capital going forward. We may need to utilize the public equity or debt markets and bank financings to fund future acquisitions or capital expenditures, but the price at which our common units will trade could be diminished as a result of the limited voting rights of unitholders. We expect to be able to issue additional equity and debt securities from time to time as market conditions allow to facilitate future acquisitions. We expect to repay any debt incurred by us to complete such acquisitions in order to meet our long-term goal of remaining substantially debt free. Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations or to refinance our indebtedness will depend on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including commodity prices, particularly for oil and natural gas, and our ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory, weather and other factors.
Current wording
As a publicly traded partnership, our primary sources of liquidity and capital resources are from cash flow generated by operating activities and borrowings under our Credit Facility. Historically, our primary sources of liquidity have also included capital contributions by our pre-IPO equity holders, but we do not expect to rely on pre-IPO equity holders for capital going forward. We may need to utilize the public equity or debt markets and bank financings to fund future acquisitions or capital expenditures, but the price at which our common units will trade could be diminished as a result of the limited voting rights of unitholders. We expect to be able to issue additional equity and debt securities from time to time as market conditions allow to facilitate future acquisitions. Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations or to refinance our indebtedness will depend on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including commodity prices, particularly for oil and natural gas, and our ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory, weather and other factors.
Previous wording
Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to our unitholders. Our quarterly cash distributions may vary from quarter to quarter as a direct result of variations in the performance of our business, including those caused by fluctuations in the prices of oil and natural gas. Such variations may be significant and quarterly distributions paid to our unitholders may be zero. Our fourth quarter distribution of $0.58 per unit with respect to cash available for distribution for the three months ended December 31, 2023, was declared on March 05, 2024 and will be paid on March 28, 2024 to unitholders of record on March 15, 2024.
Current wording
Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to our unitholders. Our quarterly cash distributions may vary from quarter to quarter as a direct result of variations in the performance of our business, including those caused by fluctuations in the prices of oil and natural gas. Such variations may be significant and quarterly distributions paid to our unitholders may be zero. Our fourth quarter distribution of $0.61 per unit with respect to cash available for distribution for the three months ended December 31, 2024, was declared on March 04, 2025 and will be paid on March 21, 2025 to unitholders of record on March 14, 2025.
Previous wording
Our acquisition and development expenditures consist of acquisitions of proved, unproved and other property and development expenditures. Our capital expenditures including acquisitions were $46.2 million for the year ended December 31, 2023 and $86.7 million for the year ended December 31, 2022.
Current wording
Our acquisition and development expenditures consist of acquisitions of proved, unproved and other property and development expenditures. Our capital expenditures including acquisitions were $288.3 million for the year ended December 31, 2024 and $46.2 million for the year ended December 31, 2023.
Previous wording
We incurred costs of approximately$29.8 million for drilling, completion and recompletion activities and facilities costs in 2023 and we have budgeted approximately$20 - $28 million for such costs in 2024. We expect to fund these capital expenditures from cash flow from operations.
Current wording
We incurred costs of approximately$28.0 million for drilling, completion and recompletion activities and facilities costs in 2024 and we have budgeted approximately$30 - $50 million for such costs in 2025. We expect to fund these capital expenditures from cash flow from operations.
Previous wording
Net cash provided by operating activities decreased $59.2 million for the year ended December 31, 2023 compared to the year ended December 31, 2022 primarily as a result of lower oil and natural gas prices in 2023 compared to 2022, increased costs and decreased production.
Current wording
Net cash provided by operating activities increased $32.1 million for the year ended December 31, 2024 compared to the year ended December 31, 2023 primarily as a result of increased production and lower expenses partially offset by lower oil and natural gas prices in 2024 compared to 2023.
Previous wording
Net cash used by investing activities decreased $40.5 million for the year ended December 31, 2023 compared to the year ended December 31, 2022 due to a decrease in proved property and other property acquisitions of $52.9 million partially offset by an increase in development costs of $12.1 million and a decrease in proceeds from sale of property of $0.3 million.
Current wording
Net cash used by investing activities increased $242.1 million for the year ended December 31, 2024 compared to the year ended December 31, 2023 due to an increase in proved property and other property acquisitions of $254.6 million related to the Williston Basin Acquisitions partially offset by a decrease in development costs of $12.6 million.
Previous wording
Net cash used in financing activities decreased $12.4 million for the year ended December 31, 2023 compared to the year ended December 31, 2022 due to proceeds from the initial public offering of $107.0 million partially offset by an increase in net repayments under our credit facility of $60.0 million and increased distributions to unitholders of $36.6 million.
Current wording
Net cash provided by financing activities increased $217.4 million for the year ended December 31, 2024 compared to the year ended December 31, 2023 due to an increase in net borrowings under our credit facility of $221.0 million and increased proceeds from public offerings of$35.0 million partially offset by increased distributions to unitholders of$35.6 millionand increased debt offering costs of$3.0 million.
Previous wording
On November 1, 2021, we entered into a new four-year, $165 million senior secured credit facility (the “Credit Facility”) with JPMorgan Chase Bank, N.A., as administrative agent, and certain commercial banks as lenders. Our Credit Facility permits us to use proceeds for general partnership purposes including distributions to our unitholders. Our obligations under the Credit Facility are secured by substantially all of our assets, including (i) our interest in Cross Timbers, (ii) all our deposit accounts, securities accounts, and commodities accounts, (iii) any receivables owed to us by the joint venture and (iv) any oil and gas properties owned directly by us and our wholly-owned subsidiaries. The facility has a maturity date of November 1, 2025. In connection with entering into the Credit Facility, as of December 31, 2023, we incurred financing fees and expenses of approximately $3.0 million before accumulated amortization of $1.5 million. These costs are being amortized over the life of the Credit Facility. Such amortized expenses are recorded as interest expense on the statements of operations. As of December 31, 2023, we had $21 million in borrowings outstanding under our Credit Facility and $144 million in availability.
Current wording
On August 30, 2024, we entered into Amendment No. 4 and Borrowing Base Agreement (“Amendment No. 4”) on our senior secured credit facility (the “Credit Facility”) with certain commercial banks, as the lenders, and JPMorgan Chase Bank, N.A., as the administrative agent. We use the Credit Facility for general corporate purposes. Amendment No. 4 extended the maturity date of the Credit Facility to August 30, 2028, increased the borrowing base from $165 million to $275 million and joined certain new Lenders to the Credit Facility. Our Credit Facility permits us to use proceeds for general partnership purposes including distributions to our unitholders. Our obligations under the Credit Facility are secured by substantially all of our assets, including (i) our interest in Cross Timbers, (ii) all our deposit accounts, securities accounts, and commodities accounts, (iii) any receivables owed to us by the joint venture and (iv) any oil and gas properties owned directly by us and our wholly-owned subsidiaries. In connection with entering into the Credit Facility, as of December 31, 2024, we incurred financing fees and expenses of approximately $6.2 million before accumulated amortization of $2.5 million. These costs are being amortized over the life of the Credit Facility. We incurred $3.1 million of financing fees and expenses in conjunction with Amendment No. 4. Such amortized expenses are recorded as interest expense on the statements of operations. As of December 31, 2024, we had $150 million in borrowings outstanding under our Credit Facility and $125 million in availability.
Previous wording
Under our Credit Facility, the borrowing base is determined based on the value of our oil and natural gas properties and the oil and gas properties of our wholly owned subsidiaries. The borrowing base is subject to further adjustments for asset dispositions, material title deficiencies, certain terminations of hedge agreements and issuances of permitted additional indebtedness. As of October 25, 2023, the last date of redetermination, our borrowing base was $165 million.
Current wording
Under our Credit Facility, the borrowing base is determined based on the value of our oil and natural gas properties and the oil and gas properties of our wholly owned subsidiaries. The borrowing base is subject to further adjustments for asset dispositions, material title deficiencies, certain terminations of hedge agreements and issuances of permitted additional indebtedness.
Previous wording
At our election, interest on borrowings under the Credit Facility is determined by reference to either the secured overnight financing rate (“SOFR”) plus an applicable margin between 3.00% and 4.00% per annum (depending on the then-current level of borrowings under the Credit Facility) or the alternate base rate (“ABR”) plus an applicable margin between 2.00% and 3.00% per annum (depending on the then-current level of borrowings under the Credit Facility). Interest is generally payable quarterly for loans bearing interest based on the ABR and at the end of the applicable interest period for loans bearing interest at SOFR. We are required to pay a commitment fee to the lenders under the Credit Facility, which accrues at a rate per annum of 0.5% on the average daily unused amount of the aggregate commitments under the Credit Facility minus the aggregate outstanding principal amount of all advances at such time. The weighted average interest rate on Credit Facility borrowings was 8.4% in 2023. The effective borrowing rate under our Credit Facility was 8.6% as of December 31, 2023.
Current wording
At our election, interest on borrowings under the Credit Facility is determined by reference to either the secured overnight financing rate (“SOFR”) plus an applicable margin between 3.00% and 4.00% per annum (depending on the then-current level of borrowings under the Credit Facility) or the alternate base rate (“ABR”) plus an applicable margin between 2.00% and 3.00% per annum (depending on the then-current level of borrowings under the Credit Facility). Interest is generally payable quarterly for loans bearing interest based on the ABR and at the end of the applicable interest period for loans bearing interest at SOFR. We are required to pay a commitment fee to the lenders under the Credit Facility, which accrues at a rate per annum of 0.5% on the average daily unused amount of the aggregate commitments under the Credit Facility minus the aggregate outstanding principal amount of all advances at such time. The weighted average interest rate on Credit Facility borrowings was 8.6% in 2024. The effective borrowing rate under our Credit Facility was 8.3% as of December 31, 2024.
Previous wording
We are required to maintain (i) a current ratio greater than 1.0 to 1.0 and current assets shall include availability under the credit facility but shall exclude the fair value of derivative instruments and any advances under the facility and (ii) a ratio of total indebtedness-to-EBITDAX of not greater than 3.0 to 1.0. For purposes of the total net debt-to-EBITDAX ratio (“Leverage Ratio”), total net debt includes total debt for borrowed money (including capital leases and purchase money debt), minus unrestricted cash and cash equivalents on hand at such time (not exceeding $15.0 million in the aggregate), minus the unpaid balance of the FAM Loan. EBITDAX means sum of (i) net income plus interest expense; income taxes paid; depreciation, depletion and amortization; exploration expenses, including workover expenses; non-cash charges including unrealized losses on derivative instruments; and, any extraordinary or non-recurring charges, minus (ii) any extraordinary or non-recurring income and any non-cash income including unrealized gains on derivative instruments. Effective with the Second Amendment entered in June 2023 (the “Second Amendment”), our hedge requirements are based on availability under the Credit Facility and the Leverage Ratio. If the Leverage Ratio is greater than 0.75 to 1.00, we are required tohedge at least 50% of reasonably anticipated projected production of proved developed producing reserves for the 24 months following the end of the most recent quarter. If the Leverage Ratio is less than 0.75 to 1.00 and availability under the Credit Facility is greater than 20% of the then current borrowing base, the minimum required hedge volume would be 35% for the 12 months following the end of the most recent quarter. If the Leverage Ratio is less than 0.50 to 1.00 and availability under the Credit Facility is greater than 66.7% of the then current borrowing base, there would be no minimum required hedge volume. Our Credit Facility prohibits us from hedging more than 90% of our reasonably projected production for any fiscal year. Under the terms of the Credit Facility as amended by the Second Amendment, we were in compliance with all of our debt covenants as of December 31, 2023. From September 30, 2022 through the date of the spring redetermination in June 2023, we received waivers to reduce the hedging requirement from 30 months to 15 months and from 50% to 45% of the reasonably projected production. As a result, we were in compliance with all of our debt covenants as of December 31, 2022. Additionally, we believe we have adequate liquidity to continue as a going concern for at least the next twelve months from the date of this report.
Current wording
We are required to maintain (i) a current ratio greater than 1.0 to 1.0 and current assets shall include availability under the credit facility but shall exclude the fair value of derivative instruments and any advances under the facility and (ii) a ratio of total indebtedness-to-EBITDAX of not greater than 3.0 to 1.0. For purposes of the total net debt-to-EBITDAX ratio (“Leverage Ratio”), total net debt includes total debt for borrowed money (including capital leases and purchase money debt), minus unrestricted cash and cash equivalents on hand at such time (not exceeding $15.0 million in the aggregate), minus the unpaid balance of the FAM Loan. EBITDAX means sum of (i) net income plus interest expense; income taxes paid; depreciation, depletion and amortization; exploration expenses, including workover expenses; non-cash charges including unrealized losses on derivative instruments; and, any extraordinary or non-recurring charges, minus (ii) any extraordinary or non-recurring income and any non-cash income including unrealized gains on derivative instruments. Effective with the Second Amendment entered in June 2023 (the “Second Amendment”), our hedge requirements are based on availability under the Credit Facility and the Leverage Ratio. If the Leverage Ratio is greater than 0.75 to 1.00, we are required tohedge at least 50% of reasonably anticipated projected production of proved developed producing reserves for the 24 months following the end of the most recent quarter. If the Leverage Ratio is less than 0.75 to 1.00 and availability under the Credit Facility is greater than 20% of the then current borrowing base, the minimum required hedge volume would be 35% for the 12 months following the end of the most recent quarter. If the Leverage Ratio is less than 0.50 to 1.00 and availability under the Credit Facility is greater than 66.7% of the then current borrowing base, there would be no minimum required hedge volume. Our Credit Facility prohibits us from hedging more than 90% of our reasonably projected production for any fiscal year. Under the terms of the Credit Facility, we were in compliance with all of our debt covenants as of December 31, 2024 and December 31, 2023. Additionally, we believe we have adequate liquidity to continue as a going concern for at least the next twelve months from the date of this report.
Previous wording
We have entered into derivative instruments to hedge our exposure to commodity price fluctuations. If market prices are higher than the contract prices when the cash settlement amount is calculated, we are required to pay the contract counterparties. As of December 31, 2023, the current liability related to such contracts was $4.0 million and the non-current liability was $0.0 million. Such payments will generally be funded by higher prices received from the sale of oil, NGLs and natural gas.
Current wording
We have entered into derivative instruments to hedge our exposure to commodity price fluctuations. If market prices are higher than the contract prices when the cash settlement amount is calculated, we are required to pay the contract counterparties. As of December 31, 2024, the current liability related to such contracts was $5.8 million and the non-current liability was $8.0 million. Such payments will generally be funded by higher prices received from the sale of oil, NGLs and natural gas.
Previous wording
At December 31, 2023, we had asset retirement obligations of $154.0 million inclusive of a current portion of $1.8 million. For further information on asset retirement obligations, see Note 7 in the financial statements included in Item 8. Financial Statements and Supplementary Data.
Current wording
At December 31, 2024, we had asset retirement obligations of $190.9 million inclusive of a current portion of $2.0 million. For further information on asset retirement obligations, see Note 7 in the financial statements included in Item 8. Financial Statements and Supplementary Data.
Previous wording
•Andrews Parker Acquisition. The acquisition in December 2021 of producing properties in the Permian Basin of Texas for approximately $43.7 million.
Current wording
•Williston Basin Acquisitions. The acquisition in August 2024 of producing properties in the Williston Basin of Montana and North Dakota for approximately $312.6 million.
Previous wording
The oil and natural gas industry is cyclical and commodity prices are highly volatile. During the period from January 1, 2021 through December 31, 2023, prices for crude oil and natural gas reached a high of $123.70 per Bbl and $9.68 per MMBtu, respectively, and a low of $47.62 per Bbl and $1.99 per MMBtu, respectively. Oil prices steadily increased through 2021 due to continued recovery in demand before increasing drastically in the first half of 2022 due to further demand, domestic supply reductions, OPEC control measures and market disruptions resulting from the Russia-Ukraine war and sanctions on Russia. Since the Russia-Ukraine conflict first commenced, WTI crude oil prices have been volatile, reaching a high of $123.70 per Bbl in March 2022 before declining to $77.82 per Bbl as of January 30, 2024. Natural gas prices reached a high of $9.68 per MMbtu in August 2022 before declining to $2.08 per MMbtu as of January 30, 2024.
Current wording
The oil and natural gas industry is cyclical and commodity prices are highly volatile. During the period from January 1, 2022 through December 31, 2024, prices for crude oil and natural gas reached a high of $123.70 per Bbl and $9.68 per MMBtu, respectively, and a low of $65.75 per Bbl and $1.58 per MMBtu, respectively. Oil prices increased drastically in the first half of 2022 due to demand, domestic supply reductions, OPEC control measures and market disruptions resulting from the Russia-Ukraine war and sanctions on Russia. Oil prices moderated over the second half of 2022 and the first half of 2023 before initially increasing in the second half of 2023 as a result of expected supply constraints and hostilities in the Middle East. Since these concerns did not materialize, oil prices declined in December 2023 but continuing hostilities and higher global consumption pushed prices higher in the first half of 2024. However, increased supply led to lower prices in the second half of 2024 declining to $72.73 per Bbl as of January 30, 2025. Natural gas prices reached a high of $9.68 per MMbtu in August 2022 before declining to 1.58 per MMBtu in March 2024 and then rebounding to $3.05 per MMbtu as of January 30, 2025.
Showing the first 40 of 44 pairs. Open the source sections for the rest.
Rearranged current paragraphs (1)
Current report — wording carried from elsewhere
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Rearranged previous paragraphs (5)
Previous report — wording carried elsewhere
The following table presents historical production volumes for our properties for the periods specified below:
Previous report — wording carried elsewhere
We plan to continue our practice of opportunistically entering into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations. Effective with our June 2023 amendment to the Credit
Previous report — wording carried elsewhere
Facilityour hedge requirements are based on availability under the Credit Facility and the Leverage Ratio. If the Leverage Ratio is greater than 0.75 to 1.00, we are required tohedge at least 50% of reasonably anticipated projected production of proved developed producing reserves for the 24 months following the end of the most recent quarter. If the Leverage Ratio is less than 0.75 to 1.00 and availability under the Credit Facility is greater than 20% of the then current borrowing base, the minimum required hedge volume would be 35% for the 12 months following the end of the most recent quarter. If the Leverage Ratio is less than 0.50 to 1.00 and availability under the Credit Facility is greater than 66.7% of the then current borrowing base, there would be no minimum required hedge volume. Our Credit Facility prohibits us from hedging more than 90% of our reasonably projected production for any fiscal year. Under the terms of the Credit Facility as amended by the Second Amendment, we were in compliance with all of our debt covenants as of December 31, 2023. From September 30, 2022 through the spring redetermination, we received waivers to reduce the hedging requirement from 30 months to 15 months and from 50% to 45% of the reasonably anticipated projected production. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving credit agreement” for more information. Our policy is to consider hedging a portion of our production at commodity prices management deems attractive.
Previous report — wording carried elsewhere
Net cash (used by) provided by financing activities
Previous report — wording carried elsewhere
•Vacuum Acquisition. The acquisition in November 2021 of producing properties and a gas processing plant in the Permian Basin of New Mexico and CO 2 assets in Colorado for approximately $179.3 million.