What changed in this filing

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Item 7. Management’s Discussion and Analysis

2025-02-11 compared with 2024-02-13 · 101 added, 109 removed, 331 unchanged (39% of the section changed)

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Discussion and analysis of our operating highlights and financial results of operations for the year ended December 31, 2023, compared to the year ended December 31, 2022, is included under the headings in Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Operating Highlights, Financial Results of Operations, Liquidity and Capital Resources, and Critical Accounting Estimates” in our Annual Report on Form 10-K for the year ended December 31, 2023, filed with the SEC on February 13, 2024.

We provide compression services in shale plays throughout the U.S., including the Utica, Marcellus, Permian Basin, Delaware Basin, Eagle Ford, Mississippi Lime, Granite Wash, Woodford, Barnett, Haynesville, Niobrara, and Fayetteville shales.

Demand for our services is driven by the domestic production of natural gas and crude oil.

As such, we have focused our activities in areas with attractive natural gas and crude oil production, which generally are found in these shale and unconventional resource plays.

According to studies promulgated by the EIA, the production and transportation volumes in these shale plays are expected to collectively increase over the long term.

We have focused our compression services in unconventional resource plays throughout the U.S., including the Utica, Marcellus, Permian, Denver-Julesburg, Eagle Ford, Mississippi Lime, Granite Wash, Woodford, Barnett, and Haynesville.

According to studies promulgated by the EIA, the production and transportation volumes in these unconventional plays, namely tight oil and gas shale plays, are expected to collectively increase over the long term.

Furthermore, changes in production volumes and pressures of shale plays over time require a wider range of compression service levels than in conventional basins.

We believe we are well-positioned to meet these changing operating conditions due to the operational design flexibility inherit within our compression-unit fleets.

Our business largely focuses on compression services serving infrastructure applications, including centralized natural gas gathering systems and processing facilities, which utilize large horsepower compression units, typically in shale plays.

We also provide compression services in more mature basins, including gas lift applications on crude oil wells targeted by horizontal drilling techniques.

Our business includes compression services serving infrastructure applications, including centralized natural gas gathering systems and processing facilities, which utilize large-horsepower compression units and also gas lift applications on crude oil wells targeted by horizontal drilling techniques.

Gas lift is a process by which natural gas is injected into the production tubing of an existing producing well to reduce hydrostatic pressure and allow the oil to flow at a higher rate.

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In addition to our natural gas infrastructure applications, a portion of our small- and large-horsepower fleet is used in connection with gas-lift applications for crude oil production targeted by horizontal drilling techniques.

We deliver natural gas compression services in connection with domestic natural gas production that primarily occurs in natural gas basins, such as the Marcellus, Utica, and Haynesville Shales, and in crude oil basins where “associated” natural gas is produced alongside crude oil, such as in the Permian and Delaware Basins, Eagle Ford, and the Mid-Continent.

Relative stability in commodity prices over much of the past decade encouraged investment in domestic exploration and production and midstream infrastructure across the energy industry, particularly in low-cost U.S.

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The development of these basins has created additional incremental demand for natural gas compression as it is a critical method to transport associated gas volumes or enhance crude oil production through gas lift.

Following a sustained period of general stability and moderate growth for the midstream sector and the broader energy industry, the events of 2020—including the COVID-19 pandemic and worldwide crude oil price dislocations related to actions taken by members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC and other allied producing countries, “OPEC+”)—impacted participants across the energy industry, including us and our customers.

The significant price volatility in both crude oil and natural gas adversely impacted energy companies’ financial performance,

and combined with reduced and uncertain future demand, created a market environment that compelled industry participants to pivot toward a renewed focus on restoring balance sheet strength, driven in part by undertaking meaningful reductions in capital investment.

Since 2020, the general energy industry recovered substantially from the low commodity prices and reduced economic activity, driven by continued demand growth for crude oil and natural gas that occurred as worldwide economic recovery from COVID-19 lock-downs commenced.

This continued demand growth for crude oil and natural gas resulted in continued growth in capital expenditures by industry participants resulting in record U.S.

crude oil and natural gas production in 2023, according to the EIA’s January 2024 Short-Term Energy Outlook (“EIA Outlook”), as the commodity-price backdrop remained constructive.

Although our business is focused on providing compression services that do not bear direct exposure to commodity prices, our business exhibits indirect exposure to commodity prices as overall levels of drilling activity and production are influenced by prevailing commodity prices.

Accordingly, we experienced increased demand for our compression services in 2023 as evidenced by marked improvements to our fleet utilization rates and pricing for our services.

According to the EIA Outlook, global consumption of petroleum and liquids fuels increased 2% in 2023 and will continue to increase over 1.0 million barrels per day (“bpd”) in each of 2024 and 2025.

With average natural gas prices down year-over-year and average oil prices relatively flat, we experienced improvements to pricing and fleet utilization for our compression services in 2024, largely tied to associated gas growth from oil plays.

Looking ahead, global consumption of petroleum and liquids fuels according to the EIA’s January 2025 Short Term Energy Outlook (“EIA Outlook”) increased in 2024 and is expected to increase over 1.3 million barrels per day (“bpd”) in 2025 and 1.1 million bpd in 2026.

The EIA Outlook estimates that annual U.S.

crude oil production averaged 12.9 million bpd in 2023, up 1.0 million bpd from 2022, primarily due to production growth in the Permian region of western Texas and eastern New Mexico.

crude oil production set a record of 13.2 million bpd in 2024, due to production growth in the Permian.

In 2025 and 2026, the EIA Outlook expects U.S.

crude oil production growth to continue, albeit at a slower rate, estimating average production of 13.2 million bpd for 2024 and 13.4 million bpd in 2025, which would represent new records for annual average crude oil production.

The estimated increase in crude oil production is due in part to the expectation that crude oil prices will remain economic for producers.

The EIA Outlook estimates that West Texas Intermediate crude oil prices will average $78 per barrel and $75 per barrel for 2024 and 2025, respectively.

However, the EIA Outlook notes several key uncertainties that could affect future prices.

Heightened tensions around the critical Red Sea shipping channel and other developments in the Middle East have the potential to disrupt global oil trade flows and drive-up global oil prices further should they escalate or persist.

We expect that anticipated crude oil production increases likewise will increase associated natural gas production volumes throughout 2024, thereby increasing demand for our compression services, particularly in the Permian and Delaware Basins.

crude oil production growth to continue, albeit at a lower crude oil price, estimating average production of 13.5 million bpd for 2025 and 13.6 million bpd in 2026, which would represent new records for annual average crude oil production.

crude oil production growth in 2025 and 2026 is expected to come almost entirely from the Permian, which is expected to account for over half of U.S.

crude oil production by 2026.

We expect that anticipated crude oil production increases likewise will increase associated natural gas production volumes throughout 2025, thereby increasing demand for our compression services.

Unlike crude oil, natural gas production and prices have been influenced by different factors, including the nonexistence of an OPEC+ equivalent for the global natural gas market, which makes natural gas price discovery dependent on market supply and demand dynamics rather than by a centralized market coordinator.

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These low prices, combined with a general shift away from coal-fired power plants due to emissions concerns, has resulted in power generation becoming, and remaining, the largest use of natural gas in the U.S., and has created a relatively resilient baseload demand for natural gas.

The demand for domestic natural gas also continues to benefit from the construction of LNG export infrastructure, which enables industry participants to benefit from attractive global natural gas prices.

Growth in power demands from the development of artificial intelligence is also expected to increase demand.

Finally, the demand for domestic natural gas also continues to benefit from the construction of LNG export infrastructure, which enables industry participants to benefit from attractive global natural gas prices.

According to the EIA Outlook, the U.S.

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Overall, the EIA Outlook expects U.S.

natural gas consumption to increase by almost 2 bcf/d in 2024, primarily reflecting increased exports, both by pipeline and LNG, but also increased residential and commercial consumption due to the expectation of colder weather in 2024 as compared to 2023, which outpaces supply growth during 2024 by 0.7 bcf/d.

Further, the EIA Outlook expects U.S natural gas consumption to increase another 2.4 bcf/d in 2025, driven primarily by LNG exports while baseload demand remains consistent, and for demand growth to exceed supply growth by 1.0 bcf/d in 2025.

Natural gas prices averaged $2.54 per million British thermal units (“MMBtu”) in 2023 and the EIA Outlook expects natural gas prices to increase on average to $2.66/MMBtu and $2.95/MMBtu in 2024 and 2025, respectively.

However, the EIA Outlook notes the potential exists for natural gas prices to rise significantly due to the uncertainty of weather impacts on residential and commercial heating demand in the winter and air conditioning demand from the electric power sector in the summer.

We expect the baseload natural gas demand described above to continue to support long-term domestic natural gas production.

The broader outlook for commodity prices remained constructive during 2023.

Although we believe the longer-term outlook for natural gas fundamentals remains positive for 2024 and beyond, the uncertainty created by the heightened tensions in the Middle East, the Russia-Ukraine conflict, the slowing global economy and general geopolitical events on the demand for crude oil and natural gas may have a varying impact on our business.

Given these uncertainties, we believe it prudent to reduce

our estimated 2024 growth capital expenditures to between $115.0 million and $125.0 million, compared to 2023 growth capital expenditures of $275.4 million.

natural gas demand to outpace production and to increase by 3.2 bcf/d in 2025, primarily reflecting increased exports, both by LNG and pipeline, and stable baseload demand.

Further, the EIA Outlook expects U.S natural gas demand to increase another 2.6 bcf/d in 2026, again driven primarily by LNG and pipeline exports, and stable baseload.

Natural gas prices averaged $2.20 per million British thermal units (“MMBtu”) in 2024 and the EIA Outlook expects natural gas prices to increase on average to $3.10/MMBtu and $4.00/MMBtu in 2025 and 2026, respectively, driven by the expectation that domestic natural gas inventories remain at or below previous five-year averages.

We expect the baseload natural gas demand and increase in LNG and pipeline exports described above, along with growth in data center demand tied to the development of artificial intelligence which we believe is not fully considered in the EIA Outlook’s numbers, to continue to support long-term domestic natural gas production.

The longer-term outlook for commodity prices remains constructive and we are increasing our new, large-horsepower compression unit order in 2025 to meet our customer needs.

We expect total capital to be between $158.0 million and $182.0 million in 2025 and are beginning to evaluate new, large-horsepower compression unit orders for 2026.

As we look forward over the next year, active geopolitical situations like those in the Middle East and Ukraine, global trade policies, inflationary pressures and slowing global GDP growth, might temper our longer-term outlook.

Ultimately, the extent to which our business will be impacted by the factors described above, as well as future developments beyond our control, cannot be predicted with reasonable certainty.

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(1) Fleet horsepower is horsepower for compression units that have been delivered to us (and excludes units on order).

As of December 31, 2023, we had 52,500 large horsepower on order for expected delivery during 2024.

(2) Total available horsepower is revenue-generating horsepower under contract for which we are billing a customer, horsepower in our fleet that is under contract but is not yet generating revenue, horsepower not yet in our fleet that is under contract but not yet generating revenue and that is subject to a purchase order, and idle horsepower.

Total available horsepower excludes new horsepower on order for which we do not have an executed compression services contract.

(1) Fleet horsepower is horsepower for compression units that have been delivered to us and excludes 20,310 and 21,690 of non-marketable horsepower as of December 31, 2024, and 2023, respectively.

As of December 31, 2024, we had no horsepower on order.

Subsequent to December 31, 2024, the Partnership ordered 10,000 large horsepower for expected delivery during 2025.

Total available horsepower excludes new horsepower expected to be delivered for which we do not have an executed compression services contract.

(3) Revenue-generating horsepower is horsepower under contract for which we are billing a customer.

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(6) Calculated as the average of the month-end revenue-generating horsepower per revenue-generating compression unit for each of the months in the period.

(7) Horsepower utilization is calculated as (i) the sum of (a) revenue-generating horsepower, (b) horsepower in our fleet that is under contract, but is not yet generating revenue, and (c) horsepower not yet in our fleet that is under contract but not yet generating revenue and that is subject to a purchase order, divided by (ii) total available horsepower less idle horsepower that is under repair.

(7) Horsepower utilization is calculated as (i) the sum of (a) revenue-generating horsepower, (b) horsepower in our fleet that is under contract, but is not yet generating revenue, and (c) horsepower not yet in our fleet that is under contract but not yet generating revenue and that is expected to be delivered, divided by (ii) total available horsepower less idle horsepower that is under repair.

Horsepower utilization based on revenue-generating horsepower and fleet horsepower was 92.4% and 90.9% as of December 31, 2024, and 2023, respectively.

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Average horsepower utilization based on revenue-generating horsepower and fleet horsepower was 91.7% and 89.2% for the years ended December 31, 2024, and 2023, respectively.

The 1.6% increase in fleet horsepower as of December 31, 2023, compared to December 31, 2022, primarily was due to compression units added to our fleet to meet incremental demand from customers for our compression services, partially offset by compression units impaired since the previous period.

The 7.3% increase in revenue-generating horsepower and 2.9% increase in revenue-generating compression units as of December 31, 2023, compared to December 31, 2022, primarily were driven by both the redeployment of, and addition of new, large-horsepower compression units due to increased demand for our services commensurate with increased production levels

in the basins in which we operate.

The above-stated factors also drove the 8.5% increase in the average revenue-generating horsepower for the year ended December 31, 2023 as compared to the year ended December 31, 2022.

The 2.3% increase in fleet horsepower as of December 31, 2024, compared to December 31, 2023, primarily was driven by new compression units added to our fleet to meet incremental demand from customers for our compression services.

The increases in revenue-generating horsepower, average horsepower per revenue-generating compression unit, horsepower utilization, and horsepower utilization based on revenue-generating horsepower and fleet horsepower as of and for the year ended December 31, 2024, compared to December 31, 2023, primarily were driven by the addition and deployment of new, and redeployment of existing, large-horsepower compression units due to increased demand for our services consistent with an overall increase in crude oil and natural gas produced within the U.S.

The 8.3% increase in average revenue per revenue-generating horsepower per month for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to higher market-based rates on newly deployed and redeployed compression units, and CPI-based and other market-based price increases on existing customer contracts that occur as market conditions permit.

The 3.5% increase in average horsepower per revenue-generating compression unit for the year ended December 31, 2023, compared to the year ended December 31, 2022, was driven by both the redeployment of, and addition of new, large-horsepower compression units.

Horsepower utilization increased to 94.3% as of December 31, 2023, compared to 91.8% as of December 31, 2022.

The increase primarily was due to an increase in revenue-generating horsepower, which was driven by a combination of the redeployment of certain previously idle compression units as well as the deployment of new compression units added to the fleet.

The increase in horsepower utilization resulted from increased demand for our services, consistent with increased production levels in the basins in which we operate.

The above-stated factors also drove the increase in average horsepower utilization for the year ended December 31, 2023 as compared to the year ended December 31, 2022.

Horsepower utilization based on revenue-generating horsepower and fleet horsepower increased to 90.9% as of December 31, 2023, compared to 86.1% as of December 31, 2022.

The increase in horsepower utilization based on revenue-generating horsepower and fleet horsepower primarily was driven by the redeployment of certain previously idle compression units as well as the deployment of new compression units added to the fleet.

The increase in horsepower utilization based on revenue-generating horsepower and fleet horsepower resulted from increased demand for our services, consistent with increased production levels in the basins in which we operate.

The above-stated factors also drove the increase in average horsepower utilization based on revenue-generating horsepower and fleet horsepower for the year ended December 31, 2023 as compared to the year ended December 31, 2022.

Financial Results of Operations

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Loss (gain) on disposition of assets 4,939 (1,667) *

Impairment of compression equipment 12,346 1,487 *

Impairment of assets 913 12,346 *

Total costs and expenses 656,000 614,197 6.8 %

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Interest expense, net (193,471) (169,924) 13.9 %

Loss on extinguishment of debt (4,966) — *

Gain on derivative instrument 5,684 7,449 (23.7) %

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Contract operations revenue .

The $129.3 million increase in contract operations revenue for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily was due to (i) an 8.7% increase in average revenue per revenue-generating horsepower per month, as a result of higher market-based rates on newly deployed and redeployed compression units, and CPI-based and other market-based price increases on existing customer contracts that occur as market conditions permit, (ii) an 8.5% increase in average revenue-generating horsepower as a result of increased demand for our services, consistent with increased production levels in the basins in which we operate, and (iii) a $24.2 million increase in revenue attributable to natural gas treating services.

The $82.7 million increase in contract operations revenue for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to (i) an 8.3% increase in average revenue per revenue-generating horsepower per month, as a result of higher market-based rates on newly deployed and redeployed compression units, and CPI-based and other market-based price increases on existing customer contracts that occur as market conditions permit, (ii) a 6.0% increase in average revenue-generating horsepower as a result of increased demand for our services, consistent with an overall increase in crude oil and natural gas produced within the U.S., partially offset by (iii) an $8.9 million decrease in revenue attributable to natural gas treating services.

Average revenue per revenue-generating horsepower per month associated with our compression services provided on a month-to-month basis did not differ significantly from the average revenue per revenue-generating horsepower per month associated with our compression services provided under contracts in their primary term during the period.

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Related-party revenue was earned through related-party transactions that occur in the ordinary course of business with various affiliated entities of Energy Transfer.

The $6.1 million increase in related-party revenue for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily was due to (i) an increase in revenues attributable to natural gas treating services driven by increased demand for these services from these entities, (ii)

increased average revenue-generating horsepower under contract with these entities, and (iii) increased average revenue per revenue-generating horsepower per month, consistent with the overall increase to our contract operations revenue.

The $19.6 million increase in related-party revenue for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to revenue recognized from

existing customers acquired by Energy Transfer since the previous period that are now classified as related-party revenue in the current period.

Cost of operations, exclusive of depreciation and amortization.

The $50.4 million increase in cost of operations for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily was due to (i) a $26.0 million increase in direct expenses, primarily driven by fluids and parts due to higher costs and increased usage associated with increased revenue-generating horsepower, (ii) a $13.6 million increase in direct labor costs due to increased headcount associated with increased revenue-generating horsepower and higher employee costs, (iii) a $5.1 million increase in retail parts and service expenses, for which a corresponding increase in parts and service revenue also occurred, (iv) a $1.6 million increase in other indirect expenses primarily due to increased consumption and costs of supplies associated with increased revenue-generating horsepower, (v) a $1.5 million increase in expenses related to our vehicle fleet, primarily due to increased usage and maintenance costs associated with increased revenue-generating horsepower, and (vi) a $1.4 million increase in non-income taxes associated with increased revenue-generating horsepower in taxable jurisdictions.

The $28.0 million increase in cost of operations for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to (i) a $17.2 million increase in direct labor costs due to increased headcount associated with increased revenue-generating horsepower and higher employee costs, (ii) a $12.3 million increase in direct expenses, primarily driven by increased spending on parts resulting from higher costs and increased usage associated with increased revenue-generating horsepower, (iii) a $2.2 million increase in other indirect expenses due to increased usage associated with increased revenue-generating horsepower, and (iv) a $1.4 million increase in retail parts and service expenses, for which a corresponding increase in parts and service revenue also occurred, partially offset by (v) a $3.6 million decrease in outside maintenance costs due to reduced use of third-party labor during the current period and (vi) a $1.4 million decrease in non-income taxes.

Depreciation and amortization expense .

The $9.4 million increase in depreciation and amortization expense for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily was due to new compression units placed in service to meet incremental demand from customers and overhauls and major improvements to compression units.

The $18.7 million increase in depreciation and amortization expense for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to (i) overhauls and major improvements to compression units and (ii) new trucks added to our vehicle fleet.

Selling, general, and administrative expense .

The $11.4 million increase in selling, general, and administrative expense for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily was due to (i) a $6.3 million increase in unit-based compensation expense, primarily attributable to mark-to-market changes to our unit-based compensation liability that occurred as a result of changes to our per-unit trading price as of December 31, 2023, (ii) a $2.2 million increase to the allowance for credit losses, resulting from a $1.5 million increase to the provision for expected credit losses in the current period versus a $0.7 million reversal of previously recognized credit losses in the prior comparable period, and (iii) a $2.1 million increase in employee-related expenses, driven by increased headcount and higher employee costs.

The change in selling, general, and administrative expense for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to (i) a $5.6 million decrease in unit-based compensation expense, primarily attributable to mark-to-market changes to our unit-based compensation liability that occurred as a result of changes to our per-unit trading price as of December 31, 2024, partially offset by (ii) a $3.2 million increase to professional fees primarily related to an initiative to improve business performance, (iii) a $1.3 million increase in severance charges related to the departure of executives during the current period, and (iv) a $0.6 million increase in employee-related expenses driven by increased headcount.

Loss (gain) on disposition of assets.

The $1.7 million gain on disposition of assets for the year ended December 31, 2023, and the $1.5 million loss on disposition of assets for the year ended December 31, 2022, were related to various asset disposals.

Impairment of compression equipment .

The $12.3 million and $1.5 million impairments of compression equipment during the years ended December 31, 2023 and 2022, respectively, primarily resulted from our evaluation of the future deployment of our idle fleet assets under then-current market conditions.

The $4.9 million loss on disposition of assets for the year ended December 31, 2024, and the $1.7 million gain on disposition of assets for the year ended December 31, 2023, were related to various asset transactions.

Impairment of assets .

The $0.9 million and $12.3 million impairments of assets during the years ended December 31, 2024 and 2023, respectively, primarily resulted from our evaluation of the future deployment of our idle fleet assets under then-current market conditions.

The primary circumstances supporting these impairments were:

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As a result of our evaluations during the years ended December 31, 2024 and 2023, we retired 2 and 42 compression units, respectively, with approximately 1,260 and 37,700 aggregate horsepower, respectively, that previously were used to provide compression services in our business.

Additionally, for the year ended December 31, 2024, we recognized a $0.6 million impairment of assets related to capitalized software costs that are no longer expected to provide benefit.

Interest expense, net .

The $31.9 million increase in interest expense, net for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily was due to higher weighted-average interest rates and increased borrowings under the Credit Agreement.

The weighted-average interest rate applicable to borrowings under the Credit Agreement was 7.68% and 4.48% for the years ended December 31, 2023, and 2022, respectively, and average outstanding borrowings under our Credit Agreement were $757.6 million for the year ended December 31, 2023, compared to $580.4 million for the year ended December 31, 2022.

The $23.5 million increase in interest expense, net for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to increased aggregate borrowings and higher aggregate weighted-average interest rates under the Credit Agreement and refinanced senior notes.

Loss on extinguishment of debt.

The $5.0 million loss on extinguishment of debt for the year ended December 31, 2024 resulted from the satisfaction and discharge of the Senior Notes 2026, which constituted a legal defeasance under GAAP (the “Defeasance”).

This loss consists of the write-off of deferred financing costs of $4.3 million and the difference between (i) the purchase price of U.S.

government securities of $748.8 million, which were used for the Defeasance, and (ii) the aggregate outstanding principal balance and accrued interest of the Senior Notes 2026 of $748.1 million at the time of Defeasance.

For additional information regarding the Defeasance of the Senior Notes 2026, see Note 10 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.

Gain on derivative instrument.

In April 2023, we entered into an interest-rate swap in which we pay a fixed interest rate and receive floating interest rate payments that are indexed to the one-month SOFR.

The $7.4 million gain on derivative instrument for the year ended December 31, 2023 resulted from the increase in fair value of the interest-rate swap due to an increase in the interest-rate forward curve during the year.

We had no derivative instruments outstanding for the year ended December 31, 2022.

The $5.7 million and $7.4 million gains on derivative instrument for the years ended December 31, 2024 and 2023, respectively, resulted from the change in fair value of the interest-rate swap due to changes in the interest-rate forward curve and cash received during the respective periods.

Income tax expense.

The $0.9 million increase in income tax expense for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was related to deferred income taxes associated with the Texas Margin Tax.

Other Financial Data

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Gross margin.

The $81.8 million increase in gross margin for the year ended December 31, 2023, compared to the year ended December 31, 2022, was due to (i) a $141.6 million increase in revenues, offset by (ii) a $50.4 million increase in cost of operations, exclusive of depreciation and amortization, and (iii) a $9.4 million increase in depreciation and amortization.

The $57.6 million increase in gross margin for the year ended December 31, 2024, compared to the year ended December 31, 2023, was due to (i) a $104.3 million increase in revenues, offset by (ii) a $28.0 million increase in cost of operations, exclusive of depreciation and amortization, and (iii) an $18.7 million increase in depreciation and amortization.

Adjusted gross margin.

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The $72.3 million increase in Adjusted EBITDA for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to a $76.3 million increase in Adjusted gross margin, partially offset by a $4.2 million increase in selling, general, and administrative expenses, excluding unit-based compensation expense, severance charges, and transaction expenses.

The $59.6 million increase in DCF for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily was due to (i) a $91.2 million increase in Adjusted gross margin, (ii) a $6.2 million increase in cash received on derivative instrument, and (iii) a $1.0 million decrease in distributions on Preferred Units, partially offset by (iv) a $31.9 million increase in cash interest expense, net, (v) a $5.1 million increase in selling, general, and administrative expenses, excluding unit-based compensation expense, severance charges, and transaction expenses, and (vi) a $1.5 million increase in maintenance capital expenditures.

The $74.2 million increase in DCF for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to (i) a $76.3 million increase in Adjusted gross margin, (ii) a $30.2 million decrease in distributions on Preferred Units following the conversion of 320,000 Preferred Units into 15,990,804 common units, and (iii) a $0.6 million increase in cash received on derivative instrument, partially offset by (iv) a $22.1 million increase in cash interest expense, net, (v) a $6.7 million increase in maintenance capital expenditures, and (vi) a $4.2 million increase in selling, general, and administrative expenses, excluding unit-based compensation expense, severance charges, and transaction expenses.

For additional information regarding the conversion of the Preferred Units, see Note 11 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.

DCF Coverage Ratio .

The increase in DCF Coverage Ratio for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily was due to the increase in DCF, partially offset by increased distributions due to an increase in the number of outstanding common units.

The increase in DCF Coverage Ratio for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to the increase in DCF, partially offset by an increase in distributions from an increase in the number of common units, largely attributable to the conversion of 320,000 Preferred Units into 15,990,804 common units during 2024 and the exercise of warrants for 2,360,488 common units in November 2023.

Liquidity and Capital Resources

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Our aggregate maintenance capital expenditures for the years ended December 31, 2024 and 2023, were $31.9 million and $25.2 million, respectively.

We currently plan to spend approximately $32.0 million in maintenance capital expenditures during 2024, including parts consumed from inventory.

We currently have budgeted between $38.0 million and $42.0 million in maintenance capital expenditures during 2025, including parts consumed from inventory.

Without giving effect to any equipment that we may acquire pursuant to any future acquisitions, we currently have budgeted between $120.0 million and $140.0 million in expansion capital expenditures for 2025.

Our expansion capital expenditures for the years ended December 31, 2024 and 2023, were $243.5 million and $275.4 million, respectively.

As of December 31, 2023, we had binding commitments to purchase $53.4 million worth of additional compression units and serialized parts, all of which is expected to be settled within the next twelve months.

As of December 31, 2024, we did not have any binding commitments to purchase additional compression units and serialized parts.

Subsequent to December 31, 2024, we ordered 10,000 horsepower for expected delivery during 2025 which will cost $10.8 million, which is expected to be settled within the next twelve months.

Other Commitments

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Net cash provided by operating activities .

The $11.3 million increase in net cash provided by operating activities for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily was due to (i) an increase in cash inflows from a $91.2 million increase in Adjusted gross margin, partially offset by (ii) a $45.2 million increase in inventory purchases and (iii) a $34.6 million increase in cash paid for interest expense, net of capitalized amounts.

The $69.4 million increase in net cash provided by operating activities for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to (i) an increase in cash inflows from a $76.3 million increase in Adjusted gross margin and (ii) a $9.3 million decrease in cash paid for interest

expense, net of capitalized amounts, driven by the Defeasance of the Senior Notes 2026, partially offset by (iii) a $25.1 million increase in inventory purchases.

Net cash used in investing activities .

The $102.7 million increase in net cash used in investing activities for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily was due to a $104.3 million increase in capital expenditures, for purchases of new compression units, overhauls and major improvements, and purchases of other equipment, partially offset by a $1.7 million increase in proceeds from disposition of property and equipment.

The $30.6 million decrease in net cash used in investing activities for the year ended December 31, 2024, compared to the year ended December 31, 2023, was due to (i) a $33.7 million decrease in capital expenditures, for purchases of new compression units, overhauls and major improvements, and purchases of other equipment, and (ii) a $1.0 million increase in proceeds from insurance recovery, partially offset by (iii) a $4.0 million decrease in proceeds from disposition of property and equipment.

Net cash used in financing activities .

The $91.4 million decrease in net cash used in financing activities for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily was due to (i) an $96.2 million increase in net borrowings under the Credit Agreement, partially offset by (ii) a $3.5 million increase in cash paid related to net settlement of unit-based awards and (iii) a $1.6 million increase in common unit distributions.

The $100.1 million increase in net cash used in financing activities for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to (i) a $748.8 million increase in investments in government securities purchased in connection with the Defeasance of the Senior Notes 2026, (ii) a $325.6 million decrease in net borrowings under the Credit Agreement, (iii) an $18.2 million increase in deferred financing costs driven by the issuance of the Senior Notes 2029, and (iv) a $31.8 million increase in common unit distributions, partially offset by (v) a 1.0 billion increase in proceeds from issuance of the Senior Notes 2029, (vi) a $24.4 million decrease in Preferred Unit distributions, and (vii) a $1.1 million decrease in cash paid related to net settlement of unit-based awards.

Revolving Credit Facility

As of December 31, 2023, we had outstanding borrowings under the Credit Agreement of $871.8 million and $728.2 million of remaining unused availability of which, due to restrictions related to compliance with the applicable financial covenants, $529.1 million was available to be drawn.

The $196.0 million increase in available borrowing capacity compared to as of December 31, 2022 was due to (i) a $127.5 million increase from the inclusion of recurring tax expenses as of December 31, 2023, consistent with the calculation of EBITDA under the Credit Agreement, and (ii) a $68.5 million increase from improved financial and operating performance as of December 31, 2023.

As of December 31, 2024, we had outstanding borrowings under the Credit Agreement of $772.1 million and, after accounting for outstanding letters of credit in the amount of $0.8 million, $827.1 million of remaining unused availability of which, due to restrictions related to compliance with the applicable financial covenants, $782.5 million was available to be drawn.

As of December 31, 2024, we were in compliance with all of our covenants under the Credit Agreement.

As of February 6, 2025, we had outstanding borrowings under the Credit Agreement of $801.5 million and outstanding letters of credit of $0.8 million.

The Credit Agreement matures on December 8, 2026, except that if any portion of the Senior Notes 2026 are outstanding on December 31, 2025, the Credit Agreement will mature on December 31, 2025.

The Credit Agreement matures on December 8, 2026.

The Credit Agreement provides for an asset-based revolving credit facility to be made available to the Partnership in an aggregate amount of $1.6 billion.

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issue equity in a public or private offering;

request a modification of our covenants from our bank group;

request a modification of our covenants from

our bank group;

reduce distributions from our current distribution rate or suspend distributions altogether;

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For a more detailed description of the Credit Agreement, including the covenants and restrictions contained therein, see Note 10 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.

As of December 31, 2023, we had $725.0 million and $750.0 million aggregate principal amount outstanding on our Senior Notes 2026 and Senior Notes 2027, respectively.

The Senior Notes 2026 are due on April 1, 2026, and accrue interest at the rate of 6.875% per year.

Interest on the Senior Notes 2026 is payable semi-annually in arrears on each of April 1 and October 1.

As of December 31, 2024, we had $750.0 million and $1.0 billion aggregate principal amount outstanding on our Senior Notes 2027 and Senior Notes 2029, respectively.

On March 5, 2024, we provided notice to the holders of our Senior Notes 2026 that, contingent on receipt of the proceeds from the Senior Notes 2029, the Senior Notes 2026 would be redeemed at par on April 4, 2024.

On March 18, 2024, utilizing a portion of the proceeds from the Senior Notes 2029, we deposited government securities with the trustee to satisfy and discharge the Senior Notes 2026 under the Indenture governing the notes.

This satisfaction and discharge constituted a legal defeasance, or the Defeasance, under GAAP as of March 18, 2024 of the full outstanding principal balance of $725.0 million.

The Senior Notes 2026 were redeemed in full at par on April 4, 2024.

The Senior Notes 2027 are due on September 1, 2027, and accrue interest at the rate of 6.875% per year.

Interest on the Senior Notes 2027 is payable semi-annually in arrears on each of March 1 and September 1.

For more detailed descriptions of the Senior Notes 2026 and Senior Notes 2027, see Note 10 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.

The Senior Notes 2029 are due on March 15, 2029, and accrue interest at the rate of 7.125% per year.

Interest on the Senior Notes 2029 is payable semi-annually in arrears on each of March 15 and September 15, which commenced on September 15, 2024.

Net proceeds from the Senior Notes 2029 were used for the Defeasance, with the remainder used to reduce outstanding borrowings under our Credit Agreement.

For more detailed descriptions of the Defeasance, Senior Notes 2027, and Senior Notes 2029, see Note 10 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.

Derivative Instrument

In April 2023, we entered into an interest-rate swap to manage interest-rate risk associated with the floating-rate Credit Agreement, and in October 2023, we modified this interest-rate swap.

See Note 8 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” for more information regarding the interest-rate swap.

During the year ended December 31, 2024, we elected to terminate the interest-rate swap we previously used to manage interest-rate risk associated with the floating-rate Credit Agreement, see Note 8 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” for more information regarding the interest-rate swap.

During the years ended December 31, 2024 and 2023, distributions of $1.6 million and $1.9 million, respectively, were reinvested under the DRIP resulting in the issuance of 65,352 and 87,808 common units, respectively.

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We believe Adjusted gross margin is useful to investors as a supplemental measure of our operating profitability.

Management uses adjusted gross margin to assess operating performance as compared to historical results, budget and forecast amounts, expected return on capital investment, and our competitors.

Adjusted gross margin primarily is impacted by the pricing trends for service operations and cost of operations, including labor rates for service technicians, volume, and per-unit costs for lubricant oils, quantity and pricing of routine preventative maintenance on compression units, and property tax rates on compression units.

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We define EBITDA as net income (loss) before net interest expense, depreciation and amortization expense, and income tax expense (benefit).

We define Adjusted EBITDA as EBITDA plus impairment of compression equipment, impairment of goodwill, interest income on capital leases, unit-based compensation expense (benefit), severance charges, certain transaction expenses, loss (gain) on disposition of assets, loss (gain) on derivative instrument, and other.

We define Adjusted EBITDA as EBITDA plus impairment of assets, impairment of goodwill, interest income on capital leases, unit-based compensation expense (benefit), severance charges, certain transaction expenses, loss (gain) on disposition of assets, loss on extinguishment of debt, loss (gain) on derivative instrument, and other.

We view Adjusted EBITDA as one of management’s primary tools for evaluating our results of operations, and we track this item on a monthly basis as an absolute amount and as a percentage of revenue compared to the prior month, year-to-date, prior year, and budget.

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Moreover, our Adjusted EBITDA, as presented, may not be comparable to similarly titled measures of other companies.

Because we use capital assets, depreciation, impairment of compression equipment, loss (gain) on disposition of assets, and the interest cost of acquiring compression equipment also are necessary elements of our aggregate costs.

Because we use capital assets, depreciation, impairment of assets, loss (gain) on disposition of assets, and the interest cost of acquiring compression equipment also are necessary elements of our aggregate costs.

Unit-based compensation expense related to equity awards granted to employees also is a meaningful business expense.

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Loss (gain) on disposition of assets 4,939 (1,667)

Loss on extinguishment of debt (3) 4,966 —

Gain on derivative instrument (5,684) (7,449)

Impairment of compression equipment (3) 12,346 1,487

Impairment of assets (4) 913 12,346

Adjusted EBITDA $ 584,282 $ 511,939

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We believe it is useful to investors to exclude these expenses.

(3) This loss on extinguishment of debt is a result of the Defeasance of the Senior Notes 2026.

This amount represents the write-off of deferred financing costs of $ 4.3 million and the difference between (i) the purchase price of U.S.

government securities of $ 748.8 million and (ii) the aggregate outstanding principal balance and accrued interest of the Senior Notes 2026 of $ 748.1 million at the time of Defeasance.

(4) Represents non-cash charges incurred to decrease the carrying value of long-lived assets with recorded values that are not expected to be recovered through future cash flows.

Distributable Cash Flow

We define DCF as net income (loss) plus non-cash interest expense, non-cash income tax expense (benefit), depreciation and amortization expense, unit-based compensation expense (benefit), impairment of compression equipment, impairment of goodwill, certain transaction expenses, severance charges, loss (gain) on disposition of assets, change in fair value of derivative instrument, proceeds from insurance recovery, and other, less distributions on Preferred Units and maintenance capital expenditures.

We define DCF as net income (loss) plus non-cash interest expense, non-cash income tax expense (benefit), depreciation and amortization expense, unit-based compensation expense (benefit), impairment of assets, impairment of goodwill, certain transaction expenses, severance charges, loss (gain) on disposition of assets, loss on extinguishment of debt, change in fair value of derivative instrument, proceeds from insurance recovery, and other, less distributions on Preferred Units and maintenance capital expenditures.

We believe DCF is an important measure of operating performance because it allows management, investors, and others to compare the cash flows that we generate (after distributions on the Preferred Units but prior to any retained cash reserves established by the General Partner and the effect of the DRIP) to the cash distributions that we expect to pay our common unitholders.

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Moreover, our DCF, as presented, may not be comparable to similarly titled measures of other companies.

Because we use capital assets, depreciation, impairment of compression equipment, loss (gain) on disposition of assets, the interest cost of acquiring compression equipment, and maintenance capital expenditures are necessary components of our aggregate costs.

Because we use capital assets, depreciation, impairment of assets, loss (gain) on disposition of assets, the interest cost of acquiring compression equipment, and maintenance capital expenditures are necessary components of our aggregate costs.

Unit-based compensation expense related to equity awards granted to employees also is a meaningful business expense.

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Depreciation and amortization 264,756 246,096

Non-cash income tax benefit (52) (151)

Non-cash income tax expense (benefit) 574 (52)

Unit-based compensation expense (1) 16,552 22,169

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Loss (gain) on disposition of assets 4,939 (1,667)

Loss on extinguishment of debt (3) 4,966 —

Change in fair value of derivative instrument 1,204 (1,204)

Impairment of compression equipment (3) 12,346 1,487

Impairment of assets (4) 913 12,346

Distributions on Preferred Units (17,550) (47,775)

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We believe it is useful to investors to exclude these expenses.

(3) This loss on extinguishment of debt is a result of the Defeasance of the Senior Notes 2026.

This amount represents the write-off of deferred financing costs of $ 4.3 million and the difference between (i) the purchase price of U.S.

government securities of $ 748.8 million and (ii) the aggregate outstanding principal balance and accrued interest of the Senior Notes 2026 of $ 748.1 million at the time of Defeasance.

(4) Represents non-cash charges incurred to decrease the carrying value of long-lived assets with recorded values that are not expected to be recovered through future cash flows.

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Potential events or circumstances that reasonably could be expected to negatively affect the key assumptions we used in estimating whether or not the carrying value of our long-lived assets are recoverable include the consolidation or failure of crude oil and natural gas producers, which may result in a smaller market for our services and may cause us to lose key customers, and cost-cutting efforts by crude oil and natural gas producers, which may cause us to lose current or potential customers or achieve less revenue per customer.

If our projections of cash flows associated with our units decline, we may have to record an impairment of compression equipment in future periods.

For the years ended December 31, 2023 and 2022, we evaluated the future deployment of our idle fleet assets under then-current market conditions and retired 42 and 15 compression units, respectively, representing approximately 37,700 and 3,200 of aggregate horsepower, respectively, that previously were used to provide compression services in our business.

If our projections of cash flows associated with our units decline, we may have to record an impairment of assets in future periods.

For the years ended December 31, 2024 and 2023, we evaluated the future deployment of our idle fleet assets under current market conditions and retired 2 and 42 compression units, respectively, representing approximately 1,260 and 37,700 of aggregate horsepower, respectively, that previously were used to provide compression services in our business.

As a result, we recorded impairments of compression equipment of $0.3 million and $12.3 million for the years ended December 31, 2024, and 2023, respectively.

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These compression units were written down to their estimated salvage values, if any.

Additionally, for the year ended December 31, 2024, we recognized a $0.6 million impairment of assets related to capitalized software costs that are no longer expected to provide benefit.

Estimated Useful Lives of Property and Equipment

Property and equipment is carried at cost.

Depreciation is computed on a straight-line basis using useful lives that are estimated based on assumptions and judgments that reflect both historical experience and expectations regarding future use of

The use of different assumptions and judgments in the calculation of depreciation, especially those involving useful lives, likely would result in significantly different net book values of our assets and results of operations.

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From time to time, we and our subsidiaries may be involved in various claims and litigation arising in the ordinary course of business.

Additionally, our compliance with state and local sales tax regulations is subject to audit by various taxing authorities.

Certain taxing authorities have either claimed or issued an assessment that specific operational processes, which we and others in our industry regularly conduct, result in transactions that are subject to state sales taxes.

Additionally, our compliance with federal, state, and local tax regulations is subject to audit by various taxing authorities.

We and others in our industry have disputed these claims and assessments based on either existing tax statutes or published guidance by the taxing authorities.

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We expense legal costs as incurred, and all recorded legal liabilities are revised, as required, as better information becomes available to us.

We currently are protesting certain assessments made by the Oklahoma Tax Commission (“OTC”).

We believe it is reasonably possible that we could incur losses related to this assessment depending on whether the administrative law judge assigned by the OTC accepts our position that the transactions are not taxable and we ultimately lose any and all subsequent legal challenges to such determination.

We estimate that the range of losses we could incur is from $0 to approximately $25.8 million, including penalties and interest.

federal income tax returns for years 2019 and 2020 currently are under examination by the IRS.

We currently are protesting certain sales tax assessments made by the Oklahoma Tax Commission (“OTC”).

In August 2024, the administrative law judge (“ALJ”) assigned by the OTC accepted our position that the transactions are not taxable.

The OTC subsequently requested a motion for reconsideration, which was denied by the ALJ.

The OTC then requested an “en banc” hearing from the OTC Commissioners, which the OTC Commissioners denied and adopted the conclusions of the ALJ, thereby effectively closing the matter.

federal income tax returns for the years 2019 and 2020 currently are under examination by the IRS.

The IRS has issued preliminary partnership examination changes, along with imputed underpayment computations, for the 2019 and 2020 tax years.

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Once a final partnership imputed underpayment, if any, is determined, our General Partner may elect to either pay the imputed underpayment (including any applicable penalties and interest) directly to the IRS or, if eligible, issue a revised information statement to each unitholder, and former unitholder, with respect to an audited and adjusted return.

Allowance for Credit Losses

We maintain an allowance for credit losses for our trade accounts receivable based on specific customer collection issues and historical experience.

Our determination of the allowance for credit losses requires us to make estimates and judgments regarding our customers’ ability to pay amounts due.

We continuously evaluate the financial strength of our customers and the overall business climate in which our customers operate, and make adjustments to the allowance for credit losses as necessary.

We evaluate the financial strength of our customers by reviewing the aging of their receivables owed to us, our collection experiences with the customer, correspondence, financial information, and third-party credit ratings.

We evaluate the business climate in which our customers operate by reviewing various publicly available materials regarding our customers’ industry, including the solvency of various companies in the industry.

For the year ended December 31, 2023, we recognized a $1.5 million increase to the provision for expected credit losses.

Unfavorable developments related to customers in bankruptcy was the primary factor supporting the recognized increase to the allowance for credit losses for the year ended December 31, 2023.

For the year ended December 31, 2022, we recognized a reversal of $0.7 million to the provision for expected credit losses.

Favorable market conditions for customers, attributable to sustained increases in commodity prices, was the primary factor supporting the recognized decrease to the allowance for credit losses for the year ended December 31, 2022.

Recent Accounting Pronouncements

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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