USA Compression Partners, LP 10-K

ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements, the notes thereto, and the other financial information appearing elsewhere in this report. The following discussion includes forward-looking statements that involve certain risks and uncertainties. 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, 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. Overview 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 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. This process, and other artificial-lift technologies are critical to the enhancement of oil production from horizontal wells operating in tight shale plays. General Trends and Outlook A significant portion of our assets are utilized in natural gas infrastructure applications typically located in U.S. onshore shale plays, primarily at centralized gathering systems and processing facilities utilizing large-horsepower compression units. Given the infrastructure nature of these applications, the continued need for additional natural gas compression throughout the production cycle, and the long-term investment horizon of our customers, we generally have experienced stability in service rates and higher sustained fleet utilization rates relative to other businesses more directly tied to drilling activity and wellhead-specific economics. 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 Denver-Julesburg 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. onshore shale basins that feature crude oil and associated gas production. 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. 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. 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. 37 Table of Contents 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 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 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. The U.S. 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. 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. The EIA Outlook expects dry natural gas production to increase by 1.4 billion cubic feet per day (“bcf/d”) in 2025 and by 2.7 bcf/d in 2026, 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. 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. witnessed record LNG exports of 12.0 bcf/d during 2024 and expects LNG exports to set new records of 14.1 bcf/d and 16.2 bcf/d in 2025 and 2026, respectively, as new LNG export capacity continues to ramp up creating incremental baseload global demand. Overall, the EIA Outlook expects U.S. 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. However, we continue to believe that overall, the long-term demand for our compression services will continue given the necessity of compression in facilitating the transportation and processing of natural gas as well as the production of crude oil. 38 Table of Contents Operating Highlights The following table summarizes certain horsepower and horsepower-utilization percentages for the periods presented and excludes certain gas-treating assets for which horsepower is not a relevant metric. Year Ended December 31, 2024 2023 Increase Fleet horsepower (at period end) (1) 3,862,102 3,775,660 2.3 % Total available horsepower (at period end) (2) 3,862,942 3,831,444 0.8 % Revenue-generating horsepower (at period end) (3) 3,567,842 3,433,775 3.9 % Average revenue-generating horsepower (4) 3,528,172 3,328,999 6.0 % Average revenue per revenue-generating horsepower per month (5) $ 20.43 $ 18.86 8.3 % Revenue-generating compression units (at period end) 4,269 4,237 0.8 % Average horsepower per revenue-generating compression unit (6) 829 792 4.7 % Horsepower utilization (7): At period end 94.6 % 94.3 % 0.3 % Average for the period (8) 94.6 % 93.4 % 1.2 % ________________________ (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. (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 expected to be delivered, and idle horsepower. 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. (4) Calculated as the average of the month-end revenue-generating horsepower for each of the months in the period. (5) Calculated as the average of the result of dividing the contractual monthly rate, excluding standby or other temporary rates, for all units at the end of each month in the period by the sum of the revenue-generating horsepower at the end of each month in the period. (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 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. (8) Calculated as the average utilization for the months in the period based on utilization at the end of each month in the period. 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 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. 39 Table of Contents Financial Results of Operations Year ended December 31, 2024, compared to the year ended December 31, 2023 The following table summarizes our results of operations for the periods presented (dollars in thousands): Year Ended December 31, Increase 2024 2023 (Decrease) Revenues: Contract operations $ 885,250 $ 802,562 10.3 % Parts and service 23,897 21,890 9.2 % Related party 41,302 21,726 90.1 % Total revenues 950,449 846,178 12.3 % Costs and expenses: Cost of operations, exclusive of depreciation and amortization 312,726 284,708 9.8 % Depreciation and amortization 264,756 246,096 7.6 % Selling, general, and administrative 72,666 72,714 (0.1) % Loss (gain) on disposition of assets 4,939 (1,667) * Impairment of assets 913 12,346 * Total costs and expenses 656,000 614,197 6.8 % Operating income 294,449 231,981 26.9 % Other income (expense): 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) % Other 110 127 (13.4) % Total other expense (192,643) (162,348) 18.7 % Net income before income tax expense 101,806 69,633 46.2 % Income tax expense 2,231 1,365 63.4 % Net income $ 99,575 $ 68,268 45.9 % ________________________ * Not meaningful. Contract operations revenue . 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. Parts and service revenue . The $2.0 million increase in parts and service revenue for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily was due to an increase in maintenance work performed on units at customer locations that are outside the scope of our core maintenance activities and that are offered as a convenience, and in directly reimbursable freight and crane charges that are the financial responsibility of the customers. Demand for retail parts and services fluctuates from period to period based on varying customer needs. Related-party revenue. 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 $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 40 Table of Contents 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 $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 $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 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 $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: (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, 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 $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. 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. 41 Table of Contents Other Financial Data The following table summarizes other financial data for the periods presented (dollars in thousands): Year Ended December 31, Increase Other Financial Data: (1) 2024 2023 (Decrease) Gross margin $ 372,967 $ 315,374 18.3 % Adjusted gross margin $ 637,723 $ 561,470 13.6 % Adjusted gross margin percentage (2) 67.1 % 66.4 % 0.7 % Adjusted EBITDA $ 584,282 $ 511,939 14.1 % Adjusted EBITDA percentage (2) 61.5 % 60.5 % 1.0 % DCF $ 355,317 $ 281,113 26.4 % DCF Coverage Ratio 1.44 x 1.35 x 6.7 % ________________________ (1) Adjusted gross margin, Adjusted EBITDA, Distributable Cash Flow (“DCF”), and DCF Coverage Ratio are all non-GAAP financial measures. Definitions of each measure, as well as reconciliations of each measure to its most directly comparable financial measure(s) calculated and presented in accordance with GAAP, can be found below under the caption “Non-GAAP Financial Measures”. (2) Adjusted gross margin percentage and Adjusted EBITDA percentage are calculated as a percentage of revenue. Gross margin. 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. The $76.3 million increase in Adjusted gross margin for the year ended December 31, 2024, compared to the year ended December 31, 2023, was due to a $104.3 million increase in revenues, offset by a $28.0 million increase in cost of operations, exclusive of depreciation and amortization. Adjusted EBITDA. 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. DCF. 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, 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 Overview 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. 42 Table of Contents We believe cash generated by operating activities and, where necessary, borrowings under the Credit Agreement will be sufficient to service our debt, fund working capital, fund our estimated expansion capital expenditures, fund our maintenance capital expenditures, and pay distributions to our unitholders through 2025. Because we distribute all of our available cash, which excludes prudent operating reserves, we expect to fund any future expansion capital expenditures or acquisitions primarily with capital from external financing sources, such as borrowings under the Credit Agreement and issuances of debt and equity securities, including under the DRIP. We are not aware of any regulatory changes or environmental liabilities that we currently expect to have a material impact on our current or future operations. Please see “Capital Expenditures” below. Capital Expenditures The compression services business is capital intensive, requiring significant investment to maintain, expand, and upgrade existing operations. Our capital requirements primarily have consisted of, and we anticipate that our capital requirements will continue primarily to consist of, the following: • maintenance capital expenditures, which are capital expenditures made to maintain the operating capacity of our assets and extend their useful lives, to replace partially or fully depreciated assets, or other capital expenditures that are incurred in maintaining our existing business and related operating income; and • expansion capital expenditures, which are capital expenditures made to expand the operating capacity or operating-income capacity of assets, including by acquisition of compression units or through modification of existing compression units to increase their capacity, or to replace certain partially or fully depreciated assets that at the time of replacement were not generating operating income. We classify capital expenditures as maintenance or expansion on an individual-asset basis. Over the long term, we expect that our maintenance capital expenditure requirements will continue to increase as the overall size and age of our fleet increases. 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 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, 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 As of December 31, 2024, other commitments include operating and finance lease payments totaling $19.3 million, of which we expect to make payments of $5.2 million to be settled in the next twelve months. For a more detailed description of our lease obligations, please refer to Note 7 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”. Cash Flows The following table summarizes our sources and uses of cash for the years ended December 31, 2024 and 2023, (in thousands): Year Ended December 31, 2024 2023 Net cash provided by operating activities $ 341,334 $ 271,885 Net cash used in investing activities (202,014) (232,653) Net cash used in financing activities (139,317) (39,256) Net cash provided by operating activities . 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 43 Table of Contents 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 $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 $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, 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. 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, 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; and (ii) all of the equity interests of the Partnership’s U.S. restricted subsidiaries (subject to customary exceptions). Borrowings under the Credit Agreement bear interest at a per-annum interest rate equal to, at the Partnership’s option, either the Alternate Base Rate or SOFR plus the applicable margin. “Alternate Base Rate” means the greatest of (i) the prime rate, (ii) the applicable federal funds effective rate plus 0.50%, and (iii) one-month SOFR rate plus 1.00%. The applicable margin for borrowings varies (a) in the case of SOFR loans, from 2.00% to 2.75% per annum, and (b) in the case of Alternate Base Rate loans, from 1.00% to 1.75% per annum, and are determined based on a total-leverage-ratio pricing grid. In addition, the Borrower is required to pay commitment fees based on the daily unused amount of the Credit Agreement in an amount equal to 0.375% per annum. Amounts borrowed and repaid under the Credit Agreement may be re-borrowed, subject to borrowing base availability. 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 5.25 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; and a Secured Leverage Ratio (as defined in the Credit Agreement) of not greater than 3.00 to 1.00 or less than 0.00 to 1.00. The Credit Agreement also contains various customary representations and warranties, affirmative covenants, and events of default. We expect to remain in compliance with our covenants under the Credit Agreement throughout 2025. If our current cash flow projections prove to be inaccurate, we expect to be able to remain in compliance with such financial covenants by taking one or more of the following actions: issue equity in a public or private offering; request a modification of our covenants from 44 Table of Contents our bank group; reduce distributions from our current distribution rate or suspend distributions altogether; delay discretionary capital spending and reduce operating expenses; 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, see Note 10 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”. Senior Notes 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. 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 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. DRIP 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. Such distributions are treated as non-cash transactions in the accompanying Consolidated Statements of Cash Flows included in Part II, Item 8 “Financial Statements and Supplementary Data” of this report. See Note 12 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” for more information regarding the DRIP. Non-GAAP Financial Measures Adjusted Gross Margin Adjusted gross margin is a non-GAAP financial measure. We define Adjusted gross margin as revenue less cost of operations, exclusive of depreciation and amortization expense. 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. Adjusted gross margin should not be considered an alternative to, or more meaningful than, gross margin or any other measure presented in accordance with GAAP. Moreover, our Adjusted gross margin, as presented, may not be comparable to similarly titled measures of other companies. Because we capitalize assets, depreciation and amortization of equipment is a necessary element of our cost structure. To compensate for the limitations of Adjusted gross margin as a measure of our performance, we believe it is important to consider gross margin determined under GAAP, as well as Adjusted gross margin, to evaluate our operating profitability. 45 Table of Contents The following table reconciles Adjusted gross margin to gross margin, its most directly comparable GAAP financial measure, for each of the periods presented (in thousands): Year Ended December 31, 2024 2023 Total revenues $ 950,449 $ 846,178 Cost of operations, exclusive of depreciation and amortization (312,726) (284,708) Depreciation and amortization (264,756) (246,096) Gross margin $ 372,967 $ 315,374 Depreciation and amortization 264,756 246,096 Adjusted gross margin $ 637,723 $ 561,470 Adjusted EBITDA 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 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. Adjusted EBITDA is used as a supplemental financial measure by our management and external users of our financial statements, such as investors and commercial banks, to assess: • the financial performance of our assets without regard to the impact of financing methods, capital structure, or the historical cost basis of our assets; • the viability of capital expenditure projects and the overall rates of return on alternative investment opportunities; • the ability of our assets to generate cash sufficient to make debt payments and pay distributions; and • our operating performance as compared to those of other companies in our industry without regard to the impact of financing methods and capital structure. We believe Adjusted EBITDA provides useful information to investors because, when viewed in conjunction with our GAAP results and the accompanying reconciliations, it may provide a more complete assessment of our performance as compared to considering solely GAAP results. We also believe that external users of our financial statements benefit from having access to the same financial measures that management uses to evaluate the results of our business. Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss), operating income (loss), cash flows from operating activities, or any other measure presented in accordance with GAAP. 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 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. Therefore, measures that exclude these cost elements have material limitations. To compensate for these limitations, we believe that it is important to consider net income (loss) and net cash provided by operating activities as determined under GAAP, as well as Adjusted EBITDA, to evaluate our financial performance and liquidity. Our Adjusted EBITDA excludes some, but not all, items that affect net income (loss) and net cash provided by operating activities, and these excluded items may vary among companies. Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing comparable GAAP measures, understanding the differences between the measures, and incorporating this knowledge into their decision making. 46 Table of Contents The following table reconciles Adjusted EBITDA to net income and net cash provided by operating activities, its most directly comparable GAAP financial measures, for each of the periods presented (in thousands): Year Ended December 31, 2024 2023 Net income $ 99,575 $ 68,268 Interest expense, net 193,471 169,924 Depreciation and amortization 264,756 246,096 Income tax expense 2,231 1,365 EBITDA $ 560,033 $ 485,653 Unit-based compensation expense (1) 16,552 22,169 Transaction expenses (2) 133 46 Severance charges 2,430 841 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 assets (4) 913 12,346 Adjusted EBITDA $ 584,282 $ 511,939 Interest expense, net (193,471) (169,924) Non-cash interest expense 8,748 7,279 Income tax expense (2,231) (1,365) Transaction expenses (133) (46) Severance charges (2,430) (841) Cash received on derivative instrument 6,888 6,245 Other 1,204 1,448 Changes in operating assets and liabilities (61,523) (82,850) Net cash provided by operating activities $ 341,334 $ 271,885 ________________________ (1) For the years ended December 31, 2024 and 2023, unit-based compensation expense included $3.9 million and $4.4 million, respectively, of cash payments related to quarterly payments of DERs on outstanding phantom unit awards and $0.2 million and $0.3 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. (2) Represents certain expenses related to potential and completed transactions and other items. 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. 47 Table of Contents 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 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. DCF should not be considered an alternative to, or more meaningful than, net income (loss), operating income (loss), cash flows from operating activities, or any other measure presented in accordance with GAAP. Moreover, our DCF, as presented, may not be comparable to similarly titled measures of other companies. 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. Therefore, measures that exclude these cost elements have material limitations. To compensate for these limitations, we believe that it is important to consider net income (loss) and net cash provided by operating activities as determined under GAAP, as well as DCF, to evaluate our financial performance and liquidity. Our DCF excludes some, but not all, items that affect net income (loss) and net cash provided by operating activities, and these excluded items may vary among companies. Management compensates for the limitations of DCF as an analytical tool by reviewing comparable GAAP measures, understanding the differences between the measures, and incorporating this knowledge into their decision making. 48 Table of Contents The following table reconciles DCF to net income and net cash provided by operating activities, its most directly comparable GAAP financial measures, for each of the periods presented (in thousands): Year Ended December 31, 2024 2023 Net income $ 99,575 $ 68,268 Non-cash interest expense 8,748 7,279 Depreciation and amortization 264,756 246,096 Non-cash income tax expense (benefit) 574 (52) Unit-based compensation expense (1) 16,552 22,169 Transaction expenses (2) 133 46 Severance charges 2,430 841 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 assets (4) 913 12,346 Distributions on Preferred Units (17,550) (47,775) Maintenance capital expenditures (5) (31,923) (25,234) DCF $ 355,317 $ 281,113 Maintenance capital expenditures 31,923 25,234 Transaction expenses (133) (46) Severance charges (2,430) (841) Distributions on Preferred Units 17,550 47,775 Other 630 1,500 Changes in operating assets and liabilities (61,523) (82,850) Net cash provided by operating activities $ 341,334 $ 271,885 ________________________ (1) For the years ended December 31, 2024 and 2023, unit-based compensation expense included $3.9 million and $4.4 million, respectively, of cash payments related to quarterly payments of DERs on outstanding phantom unit awards and $0.2 million and $0.3 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. (2) Represents certain expenses related to potential and completed transactions and other items. 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. (5) Reflects actual maintenance capital expenditures for the period presented. 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. 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 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. 49 Table of Contents The following table summarizes our DCF Coverage Ratio for the periods presented (dollars in thousands): Year Ended December 31, 2024 2023 DCF $ 355,317 $ 281,113 Distributions for DCF Coverage Ratio (1) $ 245,990 $ 208,856 DCF Coverage Ratio 1.44 x 1.35 x ________________________ (1) Represents distributions to the holders of our common units as of the record date. Critical Accounting Estimates The discussion and analysis of our financial condition and results of operations is based on our financial statements. These financial statements were prepared in conformity with GAAP. As such, we are required to make certain estimates, judgments, and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the periods presented. We base our estimates on historical experience, available information, and other assumptions we believe to be reasonable under the circumstances. On an ongoing basis, we evaluate our estimates; however, actual results may differ from these estimates under different assumptions or conditions. The accounting estimates that we believe require management’s most difficult, subjective, or complex judgments, and that are the most critical to its reporting of results of operations and financial position are as follows: Long-Lived Assets Long-lived assets, which include property and equipment, and intangible assets, comprise a significant amount of our total assets. Long-lived assets to be held and used by us are reviewed to determine whether any events or changes in circumstances indicate the carrying amount of the asset may not be recoverable. For long-lived assets to be held and used, we base our evaluation on impairment indicators such as the nature of the assets, the future economic benefit of the assets, the consistency of performance characteristics of compression units in our idle fleet with the performance characteristics of our revenue-generating horsepower, any historical or future profitability measurements, and other external market conditions or factors that may be present. If such impairment indicators are present or other factors exist that indicate the carrying amount of the asset may not be recoverable, we determine whether an impairment has occurred through the use of an undiscounted cash flows analysis. If an impairment has occurred, we recognize a loss for the difference between the carrying amount and the estimated fair value of the asset. The fair value of the asset is measured using quoted market prices or, in the absence of quoted market prices, is based on an estimate of discounted cash flows, the expected net sale proceeds compared to other similarly configured fleet units we recently sold, a review of other units recently offered for sale by third parties, or the estimated component value of similar equipment we plan to continue to use. 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 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. The primary circumstances supporting these impairments were: (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. 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. 50 Table of Contents 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 our assets. 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. Commitments and Contingencies 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 federal, state, and local 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 taxes. 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. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments, or settlements. While we are unable to predict the ultimate outcome of these actions, the accounting standard for contingencies requires management to make judgments about future events that are inherently uncertain. We are required to record a loss during any period in which we believe a contingency is probable and can be reasonably estimated. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. 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 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. Our U.S. 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. 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 $28.3 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. Recent Accounting Pronouncements See Part II, Item 8 “Financial Statements and Supplementary Data”, Note 19 for recent accounting pronouncements affecting us.