What changed in this filing

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Item 7. Management’s Discussion and Analysis

2024-02-13 compared with 2023-02-14 · 103 added, 96 removed, 337 unchanged (37% of the section changed)

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See Part I “Disclosure Regarding Forward-Looking Statements” and Part I, Item 1A “Risk Factors”.

Discussion and analysis of our operating highlights and financial results of operations for the year ended December 31, 2021, compared to the year ended December 31, 2020, 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 filed for the year ended December 31, 2021, with the SEC on February 15, 2022.

Discussion and analysis of our operating highlights and financial results of operations for the year ended December 31, 2022, compared to the year ended December 31, 2021, 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, 2022, filed with the SEC on February 14, 2023.

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.

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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.

During 2021 and throughout 2022, the general energy industry recovered substantially from the low commodity prices and reduced economic activity of 2020, driven by continued demand growth for crude oil and natural gas that occurred as worldwide economic recovery from COVID-19 lock-downs commenced.

As the demand for hydrocarbons generally follows economic growth, 2022 saw further demand growth coupled with ongoing supply constraints, attributable largely to the effects of comparatively reduced capital investment across the energy sector that began prior to the COVID-19 pandemic, intensified during the pandemic, and continued during the post-pandemic period as industry participants remained committed to capital discipline.

Although the effects of the COVID-19 pandemic continue to create general economic uncertainty, many economies and industries that directly or indirectly use crude oil and natural gas have entered economic recovery, resulting in increased demand for hydrocarbons.

According to the EIA, global consumption of petroleum and liquids fuels increased over 2% in 2022 and the EIA estimates that U.S.

gross domestic product increased 1.9% in 2022, evidencing continued global economic recovery.

The EIA’s January 2023 Short-Term Energy Outlook (“EIA Outlook”) estimates that annual U.S.

crude oil production averaged 11.9 million barrels per day (“bpd”) in 2022, up 0.6 million bpd from 2021, primarily due to production growth in the Permian and Delaware Basins.

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.

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.

In 2024 and 2025, the EIA Outlook expects U.S.

crude oil production growth to continue, estimating average production of 12.4 million bpd for 2023 and 12.8 million bpd in 2024, which would represent the highest annual average crude oil production on record.

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

The EIA estimates that West Texas Intermediate crude oil prices will average $77 per barrel and $72 per barrel for 2023 and 2024, respectively.

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.

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Over the past several years, increased natural gas production in the U.S., driven by large volumes of associated gas produced from shale sources, has been a major driver of an overall decline in natural gas prices.

Significant demand for natural gas is driven by domestic power generation and industrial uses such as chemical plants, which have benefited from a lower-price environment.

The EIA Outlook expects dry natural gas production to increase by 1.5 billion cubic feet per day (“bcf/d”) in 2024 and by 1.3 bcf/d in 2025, resulting in record dry natural gas production each year.

Significant demand for natural gas is driven by domestic power generation which has benefited from a lower-price environment.

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 liquefied natural gas (“LNG”) export infrastructure, which enables industry participants to benefit from attractive global natural gas prices.

witnessed record LNG exports during 2022 according to the EIA.

The EIA Outlook expects U.S.

natural gas consumption to decrease 2% in 2023, reflecting a decrease in the use of natural gas in the electric power generation sector, as a result of milder-than-normal winter and summer weather forecasts, and an increased share of power generation from renewables.

The decreases in use for electric power generation is expected to be offset partially by other uses, including increased LNG exports and increased pipeline exports.

Natural gas prices averaged $6.42 in 2022 and the EIA Outlook expects natural gas prices to average approximately $5 for both 2023 and 2024.

However, we expect the baseload natural gas demand previously described to continue to support long-term domestic natural gas production.

Moderate crude oil production increases in major U.S.

onshore basins occurred during 2022 as a result of a constructive commodity-price backdrop.

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

Additionally, small horsepower gas lift applications have historically been more susceptible to commodity price swings, and when commodity prices are low, we have experienced, and may again experience, some pressure on service rates and utilization in small horsepower gas lift applications.

Other variables, including takeaway capacity, flaring considerations, reservoir pressure and flow rates, high switching costs associated with large-horsepower compressors (borne by our customers), and company-specific dynamics also factor into producers’ decisions with respect to their natural gas compression needs.

For example, as wells age, and the reservoir pressures continue to decline naturally, more horsepower may be required to meet the customer’s operational needs.

Conversely, decreased drilling activity may cause demand for new compression services to decline.

The broader outlook for commodity prices improved considerably during 2022, and although uncertainty with respect to future natural gas demand may have a varying impact on our business, we believe the longer-term outlook for natural gas fundamentals remains positive for 2023 and beyond.

Future demand for our compression services will depend, in part, on the strength and duration of economical commodity prices and producer activity in the basins that we service.

While we anticipate that the combination of commodity prices and demand to have a positive impact on activity levels in both the upstream and midstream energy sectors, we cannot predict the ultimate magnitude of that impact on our business and expect it to vary across our operations, depending on the region, customer, nature of our services, contract term, and other factors.

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.

witnessed record LNG exports of 11.8 bcf/d during 2023 and expects LNG exports to set new records of 12.4 bcf/d and 14.4 bcf/d in 2024 and 2025, respectively, as new LNG export capacity continues to ramp up creating incremental baseload global demand.

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.

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, 2022, we had 165,000 large horsepower on order for delivery during 2023.

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.

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Average horsepower utilization based on revenue-generating horsepower and fleet horsepower was 89.2% and 82.9% for the years ended December 31, 2023, and 2022, respectively.

The 3.7% increase in total available horsepower as of December 31, 2022, compared to December 31, 2021, primarily was due to compression units added to our fleet to meet incremental demand from customers for our compression services.

The 7.9% increase in revenue-generating horsepower and 4.4% increase in revenue-generating compression units as of December 31, 2022, compared to December 31, 2021, primarily were driven by the redeployment of certain previously idle compression units due to increased demand for our services, commensurate with increased operating activity in the oil and gas industry.

The 4.5% increase in average revenue per revenue generating horsepower per month for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to select price increases on our existing fleet.

The 2.0% increase in average horsepower per revenue-generating compression unit primarily was due to the redeployment of larger-horsepower compression units.

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 8.7% increase in average revenue per revenue-generating horsepower per month for the year ended December 31, 2023, compared to the year ended December 31, 2022, 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 and an increase in horsepower that is under contract but not yet generating revenue, which was driven by a combination of the redeployment of certain previously idle compression units as well as new units added to our fleet.

The increase in horsepower utilization is the result of increased demand for our services, consistent with increased operating activity in the oil and gas industry.

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 due to increased demand for our services, consistent with increased operating activity in the oil and gas industry.

The above-stated factor also drove the increase in average horsepower utilization based on revenue-generating horsepower and fleet horsepower for the year ended December 31, 2022, as compared to the year ended December 31, 2021.

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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Interest expense, net (169,924) (138,050) 23.1 %

Gain on derivative instrument 7,449 — *

Other 127 91 39.6 %

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Contract operations revenue .

The $63.8 million increase in contract operations revenue for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to (i) a 4.5% increase in average revenue per revenue-generating horsepower per month, as a result of Consumer Price Index (“CPI”)-based and other price increases on customer contracts that occur as market conditions permit, (ii) a 3.9% increase in average revenue-generating horsepower as a result of increased demand for our services, consistent with increased operating activity in the oil and gas industry, and (iii) an increase in revenue attributable to natural gas treating services.

Additionally, 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.

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.

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.

Parts and service revenue .

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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 $3.7 million increase in related-party revenue for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to revenue recognized from entities acquired by Energy Transfer during the previously comparable period.

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.

Cost of operations, exclusive of depreciation and amortization.

The $39.9 million increase in cost of operations for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to (i) a $19.2 million increase in direct expenses, primarily driven by fluids and parts due to higher costs and increased usage associated with higher revenue-generating horsepower, (ii) a $6.3 million increase in outside maintenance costs due to greater use and higher costs of third-party labor during the current period, (iii) a $3.6 million increase in non-income taxes, primarily due to sales tax refunds received in the prior comparable period, (iv) a $3.4 million increase in direct labor costs due to higher employee costs, (v) a $3.3 million increase in retail parts and service expenses, for which a corresponding increase in parts and service revenue also occurred, and (vi) a $2.8 million increase in expenses related to our vehicle fleet, primarily due to increased fuel costs and increased usage, as well as higher costs of maintenance during the current period.

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.

Depreciation and amortization expense .

The $2.1 million decrease in depreciation and amortization expense for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to increased asset disposals and assets reaching the end of their depreciable lives.

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.

Selling, general, and administrative expense .

The $5.2 million increase in selling, general, and administrative expense for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to (i) a $2.0 million decrease to the allowance for credit losses, resulting from a $0.7 million reversal of previously recognized credit losses in the current period versus a $2.7 million reversal in the prior comparable period, (ii) a $1.1 million increase in employee-related expenses, (iii) a $0.5 million increase in professional fees, (iv) a $0.5 million increase in severance charges, primarily attributable to the departure of one of our executives during the current period, and (v) a $0.4 million increase in other taxes.

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.

Loss (gain) on disposition of assets.

The $4.1 million increase in loss (gain) on disposition of assets for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to the exercise of a lease purchase option on certain compression units by a customer during the prior comparable period.

The remaining change primarily relates to various asset disposals.

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 $1.5 million and $5.1 million impairments of compression equipment during the years ended December 31, 2022 and 2021, respectively, primarily were the result of our evaluations of the future deployment of our idle fleet under then-existing market conditions.

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 primary circumstances supporting these impairments were:

(i) unmarketability of units into the foreseeable future, (ii) excessive maintenance costs associated with certain fleet assets, and (iii) excessive retrofitting costs that likely would prevent certain units from securing customer acceptance.

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

As a result of our evaluations during the years ended December 31, 2022 and 2021, we retired 15 and 26 compression units, respectively, for a total of approximately 3,200 and 11,000 aggregate horsepower, respectively, that previously were used to provide compression services in our business.

(i) unmarketability of certain compression units into the foreseeable future, (ii) excessive maintenance costs associated with certain fleet assets, and (iii) prohibitive retrofitting costs that likely would prevent certain compression units from securing customer acceptance.

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

As a result of our evaluations during the years ended December 31, 2023 and 2022, we retired 42 and 15 compression units, respectively, with approximately 37,700 and 3,200 aggregate horsepower, respectively, that previously were used to provide compression services in our business.

Interest expense, net .

The $8.2 million increase in interest expense, net for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to higher weighted-average interest rates and increased borrowings under

the Credit Agreement, partially offset by a decrease in amortization of debt issuance costs attributable to the amendment and restatement of the Credit Agreement in the prior comparable period.

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.

Income tax expense.

The $0.1 million increase in income tax expense for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was related to taxes associated with the Texas Margin Tax.

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.

Other Financial Data

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Gross margin.

The $34.1 million increase in gross margin for the year ended December 31, 2022, compared to the year ended December 31, 2021, was due to (i) a $72.0 million increase in revenues and (ii) a $2.1 million decrease in depreciation and amortization, partially offset by (iii) a $39.9 million increase in cost of operations, exclusive of depreciation and amortization.

Adjusted gross margin and Adjusted gross margin percentage.

The $32.0 million increase in Adjusted gross margin for the year ended December 31, 2022, compared to the year ended December 31, 2021, was due to a $72.0 million increase in revenues, partially offset by a $39.9 million increase in cost of operations, exclusive of depreciation and amortization.

The 2.6% decline in Adjusted gross margin percentage primarily was due to the inflation-driven increase in cost of operations, exclusive of depreciation and amortization, that preceded CPI-based and other price increases on customer contracts that occur as market conditions permit.

Adjusted EBITDA and Adjusted EBITDA percentage.

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.

Adjusted gross margin.

The $91.2 million increase in Adjusted gross margin for the year ended December 31, 2023, compared to the year ended December 31, 2022, was due to a $141.6 million increase in revenues, offset by a $50.4 million increase in cost of operations, exclusive of depreciation and amortization.

Adjusted EBITDA.

The $86.0 million increase in Adjusted EBITDA for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily was due to a $91.2 million increase in Adjusted gross margin, partially offset by a $5.1 million increase in selling, general, and administrative expenses, excluding unit-based compensation expense, severance charges, and transaction expenses.

The 2.5% decline in Adjusted EBITDA percentage primarily was due to the inflation-driven increase in cost of operations, exclusive of depreciation and amortization, that preceded CPI-based and other price increases on customer contracts that occur as market conditions permit.

The $12.4 million increase in DCF for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to (i) a $32.0 million increase in Adjusted gross margin, partially offset by (ii) a $10.7 million increase in cash interest expense, net, (iii) a $4.4 million increase in selling, general, and administrative expenses, excluding unit-based compensation expense, severance charges, and transaction expenses, and (iv) a $4.3 million increase in maintenance capital expenditures.

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.

DCF Coverage Ratio .

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Liquidity and Capital Resources

We operate in a capital-intensive industry, and our primary liquidity needs are to finance the purchase of additional compression units, make other capital expenditures, service our debt, fund working capital, and pay distributions.

We operate in a capital-intensive industry, and our primary liquidity needs include financing the purchase of additional compression units, making other capital expenditures, servicing our debt, funding working capital, and paying cash distributions on our outstanding preferred and common equity.

Our principal sources of liquidity include cash generated by operating activities, borrowings under the Credit Agreement, and issuances of debt and equity securities, including common units under the DRIP.

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Net cash provided by operating activities .

The $4.8 million decrease in net cash provided by operating activities for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to changes in other working capital, offset by an $18.2 million increase in net income, as adjusted for non-cash items.

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.

Net cash used in investing activities .

The $90.8 million increase in net cash used in investing activities for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to an $89.0 million increase in capital expenditures, for purchases of new compression units, reconfiguration costs, and other equipment.

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.

Net cash used in financing activities .

The $95.6 million decrease in net cash used in financing activities for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to (i) an $87.1 million increase in net borrowings under the Credit Agreement and (ii) a $9.4 million decrease in financing costs, primarily due to costs incurred related to the amendment and restatement of our Credit Agreement in the prior comparable period, partially offset by (iii) a $1.1 million increase in common unit distributions.

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.

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, 2023, we were in compliance with all of our covenants under the Credit Agreement.

As of December 31, 2022, we had outstanding borrowings under the Credit Agreement of $646.0 million, $954.0 million of availability and, subject to compliance with the applicable financial covenants, available borrowing capacity of $333.1 million.

As of February 9, 2023, we had outstanding borrowings under the Credit Agreement of $677.0 million.

As of February 8, 2024, we had outstanding borrowings under the Credit Agreement of $927.5 million and outstanding letters of credit of $0.5 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.

On December 8, 2021, the Partnership amended and restated the Credit Agreement.

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.

The Partnership’s obligations under the Credit Agreement are guaranteed by the guarantors party to the Credit Agreement, which currently consists of all of the Partnership’s subsidiaries.

In addition, the Partnership’s obligations under the Credit Agreement are secured by:

In addition, under the Credit Agreement the Partnership’s Secured Obligations (as defined therein) are secured by:

(i) substantially all of the Partnership’s assets and substantially all of the assets of the guarantors party to the Credit Agreement, excluding real property and other customary exclusions;

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The Credit Agreement contains various covenants with which the Partnership and its restricted subsidiaries must comply, including, but not limited to, limitations on the incurrence of indebtedness, investments, liens on assets, repurchasing equity and making distributions, transactions with affiliates, mergers, consolidations, dispositions of assets, and other provisions customary in similar types of agreements.

The Partnership also must maintain, on a consolidated basis, as of the last day of each fiscal quarter a Total Leverage Ratio (as defined in the Credit Agreement) of not greater than 5.50 to 1.00 through the third fiscal quarter of 2023 and 5.25 to 1.00 thereafter (except that the Partnership may increase the applicable Total Leverage Ratio by 0.25 for any fiscal quarter during which a Specified Acquisition (as defined in the Credit Agreement) occurs and the following two fiscal quarters, but in no event shall the maximum Total Leverage Ratio exceed 5.50 to 1.00 for any fiscal quarter as a

result of such increase);

The Partnership also must maintain, on a consolidated basis, as of the last day of each fiscal quarter a Total Leverage Ratio (as defined in the Credit Agreement) of not greater than 5.25 to 1.00 (except that the Partnership may increase the applicable Total Leverage Ratio by 0.25 for any fiscal quarter during which a Specified Acquisition (as defined in the Credit Agreement) occurs and the following two fiscal quarters, but in no event shall the maximum Total Leverage Ratio exceed 5.50 to 1.00 for any fiscal quarter as a result of such increase);

an Interest Coverage Ratio (as defined in the Credit Agreement) of not less than 2.50 to 1.00;

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or obtain an equity infusion pursuant to the terms of the Credit Agreement.

For a more detailed description of the Credit Agreement, including the covenants and restrictions contained therein, please refer to Note 9 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data.”.

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.

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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, please refer to Note 9 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.

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”.

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 years ended December 31, 2023 and 2022, distributions of $1.9 million and $2.1 million, respectively, were reinvested under the DRIP resulting in the issuance of 87,808 and 124,255 common units, respectively.

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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, 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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EBITDA $ 485,653 $ 406,061

Interest income on capital lease — 48

Unit-based compensation expense (1) 22,169 15,894

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Loss (gain) on disposition of assets (1,667) 1,527

Gain on derivative instrument (7,449) —

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

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Income tax expense (1,365) (1,016)

Interest income on capital lease — (48)

Transaction expenses (46) (27)

Severance charges (841) (982)

Cash received on derivative instrument 6,245 —

Other 1,448 (851)

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________________________

(1) For the years ended December 31, 2022, and 2021, unit-based compensation expense included $4.4 million and $4.2 million, respectively, of cash payments related to quarterly payments of DERs on outstanding phantom unit awards and $1.3 million and $0.3 million, respectively, related to the cash portion of any settlement of phantom unit awards upon vesting.

(1) For the years ended December 31, 2023 and 2022, unit-based compensation expense included $4.4 million and $4.4 million, respectively, of cash payments related to quarterly payments of DERs on outstanding phantom unit awards and $0.3 million and $1.3 million, respectively, related to the cash portion of the settlement of phantom unit awards upon vesting.

The remainder of unit-based compensation expense for all periods was related to non-cash adjustments to the unit-based compensation liability.

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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, 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 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 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.

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 (1,667) 1,527

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

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

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________________________

The remainder of unit-based compensation expense for all periods was related to non-cash adjustments to the unit-based compensation liability.

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Maintenance capital expenditures are capital expenditures made to maintain the operating capacity of our assets and extend their useful lives, replace partially or fully depreciated assets, or other capital expenditures that are incurred in maintaining our existing business and related cash flow.

Coverage Ratios

DCF Coverage Ratio

DCF Coverage Ratio is defined as the period’s DCF divided by distributions declared to common unitholders in respect of such period.

We believe DCF Coverage Ratio is an important measure of operating performance because it permits management, investors, and others to assess our ability to pay cash distributions to common unitholders out of the cash flows that we generate.

We believe DCF Coverage Ratio is an important measure of operating performance because it permits management, investors, and others to assess our ability to pay distributions to common unitholders out of the cash flows that we generate.

Our DCF Coverage Ratio, as presented, may not be comparable to similarly titled measures of other companies.

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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, 2022, and 2021, we evaluated the future deployment of our idle fleet assets under then-existing market conditions and retired 15 and 26 compressor units, respectively, for a total of approximately 3,200 and 11,000 aggregate horsepower, respectively, that previously were used to provide compression services in our business.

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.

As a result, we recorded impairments of compression equipment of $12.3 million and $1.5 million for the years ended December 31, 2023, and 2022, respectively.

The primary circumstances supporting these impairments were:

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

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

Estimated Useful Lives of Property and Equipment

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

As of December 31, 2021, we had recorded a $44.9 million accrued liability and $44.9 million related-party receivable from Energy Transfer related to open audits with the Office of the Texas Comptroller of Public Accounts (the “Comptroller”), wherein the Comptroller had challenged the applicability of the manufacturing exemption.

During August 2022, a Compromise and Settlement Agreement (“Agreement”) was entered into with the Comptroller for the period January 1, 2008, through March 31, 2018, related to such open audits.

Pursuant to an indemnification agreement between us and Energy Transfer, Energy Transfer paid all amounts due under the Agreement in full.

As a result, the $44.9 million accrued liability and $44.9 million related-party receivable from Energy Transfer was reduced to zero as of December 31, 2022.

federal income tax returns for 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.

Under the Bipartisan Budget Act of 2015, there are several procedural steps, including an appeals process, to complete before a final imputed underpayment, if any, is determined.

Based on discussions with the IRS, we estimate a potential range of loss from a final imputed underpayment of $0 to approximately $26.4 million, including interest, for potential adjustments resulting from the IRS examinations.

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

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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 experience with the customer, correspondence, financial information, and third-party credit ratings.

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, 2022, we recognized a reversal of $0.7 million of our provision for expected credit losses.

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

For the year ended December 31, 2021, we recognized a reversal of $2.7 million of our provision for expected credit losses.

Improved market conditions for customers resulting from improved commodity prices was the primary factor supporting the recorded decrease to the allowance for credit losses for the year ended December 31, 2021.

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

See Part II, Item 8 “Financial Statements and Supplementary Data”, Note 18 for recent accounting pronouncements affecting us.

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