Item 7. Management’s Discussion and Analysis
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, 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.
Overview
We provide compression services in shale plays throughout the U.S., including the Utica, Marcellus, Permian Basin, Delaware Basin, Eagle Ford, Mississippi Lime, Granite Wash, Woodford, Barnett, Haynesville, Niobrara, and Fayetteville shales. Demand for our services is driven by the domestic production of natural gas and crude oil. As such, we have focused our activities in areas with attractive natural gas and crude oil production, which generally are found in these shale and unconventional resource plays. According to studies promulgated by the EIA, the production and transportation volumes in these shale plays are expected to collectively increase over the long term. Furthermore, changes in production volumes and pressures of shale plays over time require a wider range of compression service levels than in conventional basins. We believe we are well-positioned to meet these changing operating conditions due to the operational design flexibility inherit within our compression-unit fleets.
Our business largely focuses on compression services serving infrastructure applications, including centralized natural gas gathering systems and processing facilities, which utilize large horsepower compression units, typically in shale plays. We also provide compression services in more mature basins, including gas lift applications on crude oil wells targeted by horizontal drilling techniques. 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 Delaware Basins, Eagle Ford, and the Mid-Continent. Relative stability in commodity prices over much of the past decade encouraged investment in domestic exploration and production and midstream infrastructure across the energy industry, particularly in low-cost U.S. 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.
Following a sustained period of general stability and moderate growth for the midstream sector and the broader energy industry, the events of 2020—including the COVID-19 pandemic and worldwide crude oil price dislocations related to actions taken by members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC and other allied producing countries, “OPEC+”)—impacted participants across the energy industry, including us and our customers. The significant price volatility in both crude oil and natural gas adversely impacted energy companies’ financial performance,
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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.
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, 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.
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 1.5 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 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
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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. 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.
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,
2023 2022 Increase
Fleet horsepower (at period end) (1) 3,775,660 3,716,854 1.6 %
Total available horsepower (at period end) (2) 3,831,444 3,826,854 0.1 %
Revenue-generating horsepower (at period end) (3) 3,433,775 3,199,548 7.3 %
Average revenue-generating horsepower (4) 3,328,999 3,067,279 8.5 %
Average revenue per revenue-generating horsepower per month (5) $ 18.86 $ 17.35 8.7 %
Revenue-generating compression units (at period end) 4,237 4,116 2.9 %
Average horsepower per revenue-generating compression unit (6) 792 765 3.5 %
Horsepower utilization (7):
At period end 94.3 % 91.8 % 2.5 %
Average for the period (8) 93.4 % 88.6 % 4.8 %
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(1) Fleet horsepower is horsepower for compression units that have been delivered to us (and excludes units on order). As of December 31, 2023, we had 52,500 large horsepower on order for expected delivery during 2024.
(2) Total available horsepower is revenue-generating horsepower under contract for which we are billing a customer, horsepower in our fleet that is under contract but is not yet generating revenue, horsepower not yet in our fleet that is under contract but not yet generating revenue and that is subject to a purchase order, and idle horsepower. Total available horsepower excludes new horsepower on order for which we do not have an executed compression services contract.
(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 subject to a purchase order, divided by (ii) total available horsepower less idle horsepower that is under repair. Horsepower utilization based on revenue-generating horsepower and fleet horsepower was 90.9% and 86.1% as of December 31, 2023, and 2022, 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 89.2% and 82.9% for the years ended December 31, 2023, and 2022, respectively.
The 1.6% increase in fleet horsepower as of December 31, 2023, compared to December 31, 2022, primarily was due to compression units added to our fleet to meet incremental demand from customers for our compression services, partially offset by compression units impaired since the previous period.
The 7.3% increase in revenue-generating horsepower and 2.9% increase in revenue-generating compression units as of December 31, 2023, compared to December 31, 2022, primarily were driven by both the redeployment of, and addition of new, large-horsepower compression units due to increased demand for our services commensurate with increased production levels
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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, which was driven by a combination of the redeployment of certain previously idle compression units as well as the deployment of new compression units added to the fleet. The increase in horsepower utilization resulted from increased demand for our services, consistent with increased production levels in the basins in which we operate. The above-stated factors also drove the increase in average horsepower utilization for the year ended December 31, 2023 as compared to the year ended December 31, 2022.
Horsepower utilization based on revenue-generating horsepower and fleet horsepower increased to 90.9% as of December 31, 2023, compared to 86.1% as of December 31, 2022. The increase in horsepower utilization based on revenue-generating horsepower and fleet horsepower primarily was driven by the redeployment of certain previously idle compression units as well as the deployment of new compression units added to the fleet. The increase in horsepower utilization based on revenue-generating horsepower and fleet horsepower resulted from increased demand for our services, consistent with increased production levels in the basins in which we operate. The above-stated factors also drove the increase in average horsepower utilization based on revenue-generating horsepower and fleet horsepower for the year ended December 31, 2023 as compared to the year ended December 31, 2022.
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Financial Results of Operations
Year ended December 31, 2023, compared to the year ended December 31, 2022
The following table summarizes our results of operations for the periods presented (dollars in thousands):
Year Ended December 31, Increase
2023 2022 (Decrease)
Revenues:
Contract operations $ 802,562 $ 673,214 19.2 %
Parts and service 21,890 15,729 39.2 %
Related party 21,726 15,655 38.8 %
Total revenues 846,178 704,598 20.1 %
Costs and expenses:
Cost of operations, exclusive of depreciation and amortization 284,708 234,336 21.5 %
Depreciation and amortization 246,096 236,677 4.0 %
Selling, general, and administrative 72,714 61,278 18.7 %
Loss (gain) on disposition of assets (1,667) 1,527 *
Impairment of compression equipment 12,346 1,487 *
Total costs and expenses 614,197 535,305 14.7 %
Operating income 231,981 169,293 37.0 %
Other income (expense):
Interest expense, net (169,924) (138,050) 23.1 %
Gain on derivative instrument 7,449 — *
Other 127 91 39.6 %
Total other expense (162,348) (137,959) 17.7 %
Net income before income tax expense 69,633 31,334 122.2 %
Income tax expense 1,365 1,016 34.4 %
Net income $ 68,268 $ 30,318 125.2 %
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* Not meaningful.
Contract operations revenue . The $129.3 million increase in contract operations revenue for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily was due to (i) an 8.7% increase in average revenue per revenue-generating horsepower per month, as a result of higher market-based rates on newly deployed and redeployed compression units, and CPI-based and other market-based price increases on existing customer contracts that occur as market conditions permit, (ii) an 8.5% increase in average revenue-generating horsepower as a result of increased demand for our services, consistent with increased production levels in the basins in which we operate, and (iii) a $24.2 million increase in revenue attributable to natural gas treating services.
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 $6.2 million increase in parts and service revenue for the year ended December 31, 2023, compared to the year ended December 31, 2022, 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 $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)
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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 $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 $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 $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 $1.7 million gain on disposition of assets for the year ended December 31, 2023, and the $1.5 million loss on disposition of assets for the year ended December 31, 2022, were related to various asset disposals.
Impairment of compression equipment . The $12.3 million and $1.5 million impairments of compression equipment during the years ended December 31, 2023 and 2022, respectively, primarily resulted from our evaluation of the future deployment of our idle fleet assets under then-current market conditions. The 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, 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 $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.
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.
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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) 2023 2022 (Decrease)
Gross margin $ 315,374 $ 233,585 35.0 %
Adjusted gross margin
$ 561,470 $ 470,262 19.4 %
Adjusted gross margin percentage (2)
66.4 % 66.7 % (0.3) %
Adjusted EBITDA
$ 511,939 $ 425,978 20.2 %
Adjusted EBITDA percentage (2)
60.5 % 60.5 % — %
DCF
$ 281,113 $ 221,499 26.9 %
DCF Coverage Ratio
1.35 x 1.08 x 25.0 %
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(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 $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.
DCF. 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 . The increase in DCF Coverage Ratio for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily was due to the increase in DCF, partially offset by increased distributions due to an increase in the number of outstanding common units.
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.
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 2024.
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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, 2023 and 2022, were $25.2 million and $23.8 million, respectively. We currently plan to spend approximately $32.0 million in maintenance capital expenditures during 2024, 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 $115.0 million and $125.0 million in expansion capital expenditures for 2024. Our expansion capital expenditures for the years ended December 31, 2023 and 2022, were $275.4 million and $145.1 million, respectively.
As of December 31, 2023, we had binding commitments to purchase $53.4 million worth of additional compression units and serialized parts, all of which is expected to be settled within the next twelve months.
Other Commitments
As of December 31, 2023, other commitments include operating and finance lease payments totaling $22.7 million, of which we expect to make payments of $5.4 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, 2023 and 2022, (in thousands):
Year Ended December 31,
2023 2022
Net cash provided by operating activities $ 271,885 $ 260,590
Net cash used in investing activities (232,653) (129,945)
Net cash used in financing activities (39,256) (130,610)
Net cash provided by operating activities . The $11.3 million increase in net cash provided by operating activities for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily was due to (i) an increase in cash inflows from a $91.2 million increase in Adjusted gross margin, partially offset by (ii) a $45.2 million increase in inventory purchases and (iii) a $34.6 million increase in cash paid for interest expense, net of capitalized amounts.
Net cash used in investing activities . The $102.7 million increase in net cash used in investing activities for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily was due to a $104.3 million increase in capital expenditures, for purchases of new compression units, overhauls and major improvements, and purchases of other equipment, partially offset by a $1.7 million increase in proceeds from disposition of property and equipment.
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Net cash used in financing activities . The $91.4 million decrease in net cash used in financing activities for the year ended December 31, 2023, compared to the year ended December 31, 2022, primarily was due to (i) an $96.2 million increase in net borrowings under the Credit Agreement, partially offset by (ii) a $3.5 million increase in cash paid related to net settlement of unit-based awards and (iii) a $1.6 million increase in common unit distributions.
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 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.
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 2024. 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 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.”.
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Senior Notes
As of December 31, 2023, we had $725.0 million and $750.0 million aggregate principal amount outstanding on our Senior Notes 2026 and Senior Notes 2027, respectively.
The Senior Notes 2026 are due on April 1, 2026, and accrue interest at the rate of 6.875% per year. Interest on the Senior Notes 2026 is payable semi-annually in arrears on each of April 1 and October 1.
The Senior Notes 2027 are due on September 1, 2027, and accrue interest at the rate of 6.875% per year. Interest on the Senior Notes 2027 is payable semi-annually in arrears on each of March 1 and September 1.
For more detailed descriptions of the Senior Notes 2026 and Senior Notes 2027, see Note 10 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.
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.
DRIP
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.
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. 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.
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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,
2023 2022
Total revenues $ 846,178 $ 704,598
Cost of operations, exclusive of depreciation and amortization (284,708) (234,336)
Depreciation and amortization (246,096) (236,677)
Gross margin $ 315,374 $ 233,585
Depreciation and amortization 246,096 236,677
Adjusted gross margin $ 561,470 $ 470,262
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 compression equipment, impairment of goodwill, interest income on capital leases, unit-based compensation expense (benefit), severance charges, certain transaction expenses, loss (gain) on disposition of assets, loss (gain) on derivative instrument, and other. We 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 compression equipment, 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.
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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,
2023 2022
Net income $ 68,268 $ 30,318
Interest expense, net 169,924 138,050
Depreciation and amortization 246,096 236,677
Income tax expense 1,365 1,016
EBITDA $ 485,653 $ 406,061
Unit-based compensation expense (1) 22,169 15,894
Transaction expenses (2) 46 27
Severance charges 841 982
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
Adjusted EBITDA $ 511,939 $ 425,978
Interest expense, net (169,924) (138,050)
Non-cash interest expense 7,279 7,265
Income tax expense (1,365) (1,016)
Transaction expenses (46) (27)
Severance charges (841) (982)
Cash received on derivative instrument 6,245 —
Other 1,448 (851)
Changes in operating assets and liabilities (82,850) (31,727)
Net cash provided by operating activities $ 271,885 $ 260,590
________________________
(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.
(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) Represents non-cash charges incurred to decrease the carrying value of long-lived assets with recorded values that are not expected to be recovered through future cash flows.
Distributable Cash Flow
We define DCF as net income (loss) plus non-cash interest expense, non-cash income tax expense (benefit), depreciation and amortization expense, unit-based compensation expense (benefit), impairment of compression equipment, impairment of goodwill, certain transaction expenses, severance charges, loss (gain) on disposition of assets, change in fair value of derivative instrument, proceeds from insurance recovery, and other, less distributions on Preferred Units and maintenance capital expenditures.
We 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.
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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. 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.
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,
2023 2022
Net income $ 68,268 $ 30,318
Non-cash interest expense 7,279 7,265
Depreciation and amortization 246,096 236,677
Non-cash income tax benefit (52) (151)
Unit-based compensation expense (1) 22,169 15,894
Transaction expenses (2) 46 27
Severance charges 841 982
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
Distributions on Preferred Units (47,775) (48,750)
Maintenance capital expenditures (4) (25,234) (23,777)
DCF $ 281,113 $ 221,499
Maintenance capital expenditures 25,234 23,777
Transaction expenses (46) (27)
Severance charges (841) (982)
Distributions on Preferred Units 47,775 48,750
Other 1,500 (700)
Changes in operating assets and liabilities (82,850) (31,727)
Net cash provided by operating activities $ 271,885 $ 260,590
________________________
(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.
(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) 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.
(4) 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.
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The following table summarizes our DCF Coverage Ratio for the periods presented (dollars in thousands):
Year Ended December 31,
2023 2022
DCF $ 281,113 $ 221,499
Distributions for DCF Coverage Ratio (1) $ 208,856 $ 205,559
DCF Coverage Ratio 1.35 x 1.08 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 compression equipment in future periods.
For the years ended December 31, 2023 and 2022, we evaluated the future deployment of our idle fleet assets under then-current market conditions and retired 42 and 15 compression units, respectively, representing approximately 37,700 and 3,200 of aggregate horsepower, respectively, that previously were used to provide compression services in our business. 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: (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.
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
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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 state and local sales tax regulations is subject to audit by various taxing authorities. Certain taxing authorities have either claimed or issued an assessment that specific operational processes, which we and others in our industry regularly conduct, result in transactions that are subject to state sales taxes. 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 assessments made by the Oklahoma Tax Commission (“OTC”). We believe it is reasonably possible that we could incur losses related to this assessment depending on whether the administrative law judge assigned by the OTC accepts our position that the transactions are not taxable and we ultimately lose any and all subsequent legal challenges to such determination. We estimate that the range of losses we could incur is from $0 to approximately $25.8 million, including penalties and interest.
Our U.S. 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
We maintain an allowance for credit losses for our trade accounts receivable based on specific customer collection issues and historical experience.
Our determination of the allowance for credit losses requires us to make estimates and judgments regarding our customers’ ability to pay amounts due. We continuously evaluate the financial strength of our customers and the overall business climate in which our customers operate, and make adjustments to the allowance for credit losses as necessary. We evaluate the financial strength of our customers by reviewing the aging of their receivables owed to us, our collection experiences with the customer, correspondence, financial information, and third-party credit ratings. We evaluate the business climate in which our customers operate by reviewing various publicly available materials regarding our customers’ industry, including the solvency of various companies in the industry.
For the year ended December 31, 2023, we recognized a $1.5 million increase to the provision for expected credit losses. Unfavorable developments related to customers in bankruptcy was the primary factor supporting the recognized increase to the allowance for credit losses for the year ended December 31, 2023.
For the year ended December 31, 2022, we recognized a reversal of $0.7 million to the provision for expected credit losses. Favorable market conditions for customers, attributable to sustained increases in commodity prices, was the primary factor supporting the recognized decrease to the allowance for credit losses for the year ended December 31, 2022.
Recent Accounting Pronouncements
See Part II, Item 8 “Financial Statements and Supplementary Data”, Note 18 for recent accounting pronouncements affecting us.
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