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, 2019 compared to the year ended December 31, 2018 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 Policies and Estimates” in our Annual Report on Form 10-K filed for the year ended December 31, 2019 with the SEC on February 18, 2020. Overview We provide compression services in a number of 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 of attractive natural gas and crude oil production growth, which are generally 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 increase over the long term. Furthermore, the changes in production volumes and pressures of shale plays over time require a wider range of compression services than in conventional basins. We believe we are well-positioned to meet these changing operating conditions due to the operational design flexibility inherit in our compression units. While our business focuses largely 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 conventional basins, including gas lift applications on crude oil wells targeted by horizontal drilling techniques. Gas lift, a process by which natural gas is injected into the production tubing of 42 Table of Contents an existing producing well, in order to reduce the hydrostatic pressure and allow the oil to flow at a higher rate, and other artificial lift technologies are critical to the enhancement of oil production from horizontal wells operating in tight shale plays. Recent Developments Credit Agreement Amendment The Credit Agreement was amended on August 3, 2020 (the “Amendment Effective Date”) to amend, among other things, the requirements of certain covenants and the date on which certain covenants in the Credit Agreement must be met beginning on the Amendment Effective Date until the last day of the fiscal quarter ending December 31, 2021 (the “Covenant Relief Period”). The amendment, among other items, increases the maximum funded debt to EBITDA ratio to (i) 5.75 to 1.00 for the fiscal quarters ending September 30, 2020 and December 31, 2020, (ii) 5.50 to 1.00 for the fiscal quarters ending March 31, 2021 and June 30, 2021 and (iii) 5.25 to 1.00 for the fiscal quarters ending September 30, 2021 and December 31, 2021 (reverting back to 5.00 to 1.00 after the Covenant Relief Period). In addition, during the Covenant Relief Period, the applicable margin for Eurodollar borrowings is increased from a range of 2.00% – 2.75% to a range of 2.25% – 3.00%. Please see Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Revolving Credit Facility” for additional information regarding the amendment to our Credit Agreement. General Trends and Outlook A significant amount of our assets are utilized in natural gas infrastructure applications typically located in shale plays, primarily in centralized gathering systems and processing facilities utilizing large horsepower compression units. Given the infrastructure nature of these applications and long-term investment horizon of our customers, we have generally experienced stability in service rates and higher sustained utilization relative to other businesses more directly tied to drilling activity and wellhead economics. In addition to our natural gas infrastructure applications, a portion of our fleet is used in connection with gas lift applications on crude oil production targeted by horizontal drilling techniques and can be accomplished by both small and large horsepower compression equipment. Domestic natural gas production generally occurs in either primarily natural gas basins, such as the Marcellus, Utica and Haynesville Shales, or in basins where natural gas is produced alongside crude oil, also known as “associated” gas, such as the Permian and Delaware Basins, Eagle Ford and the Mid-Continent. Over the recent past, relative stability in commodity prices encouraged investment in domestic exploration and production (“E&P”) and midstream infrastructure across the energy industry, particularly in the low-cost basins characterized by associated gas and crude oil production. The development of these basins producing both commodities has created additional incremental demand for natural gas compression over the recent past as it is a critical method to transport associated gas volumes or enhance crude oil production through gas lift. However, certain 2020 events have impacted, and may continue to impact, our operations in areas driven by associated gas and crude oil production. For example, in March 2020 the collapse of discussions among members of Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC and other allied producing countries, “OPEC+”), combined with Saudi Arabia’s announcement that it would be discounting its price, and increasing its supply, of crude oil into the global market created downward pressure on crude oil prices worldwide. Recent events, including reports of decreasing domestic crude oil inventory in storage as well as OPEC’s general compliance to agreed-upon production cuts and Saudi Arabia’s leadership in taking on further production cuts may be indicators of improving longer-term crude oil fundamentals which may positively impact basins where associated gas volumes are produced. Further, the ongoing global impact, both real and perceived, on crude oil demand from the COVID-19 pandemic created uncertainty regarding the demand for compression services in our operating areas driven by associated gas and crude oil production. While our business is focused on providing compression services and does not have any direct exposure to commodity prices, we have indirect exposure to commodity prices as overall levels of activity across the energy industry are influenced by the commodity price environment. As the price of crude oil fluctuated during 2020, certain of our customers reduced their demand for our services. Accordingly, we have reduced our planned capital spending significantly for 2021. The EIA’s January 2021 Short-Term Energy Outlook (“EIA Outlook”) estimates that annual U.S. crude oil production averaged 11.3 million barrels per day (“bpd”) in 2020, down 1.0 million bpd from 2019 reflecting the impact of well curtailments and a decrease in drilling activity related to low crude oil prices. While the price of crude oil rebounded during the second quarter of 2020 and remained relatively stable during the third and fourth quarters of 2020, and rig counts have 43 Table of Contents increased modestly since the recent bottom during summer 2020, many E&P companies, including some of our customers, continue to take a cautious approach to development plans and budget for reduced capital expenditure forecasts. The EIA Outlook forecasts total U.S. crude oil production in 2021 to decline again, averaging 11.1 million bpd, before increasing to 11.5 million bpd in 2022. Taking into account an approximate six-month lag between changes in crude oil prices and changes in crude oil production, the EIA Outlook expects production from the Lower 48 states to decline through February 2021 before showing steady increases throughout the remainder of 2021; ending 2021 with an aggregate 3% decline in Lower 48 production. We expect the reduction in capital spending during 2020 to result in a decrease in new production, in turn negatively affecting the demand for new compression services in the near term. Further, while the Permian and Delaware Basins, one of our largest operating areas on a horsepower basis, still benefit from favorable geology as well as technological and operational improvements that have benefited operators in the region; overall reduced drilling activity and the typically steep well decline curves are expected to have an impact on production. As an example, the EIA Outlook expects two-thirds of U.S Lower 48 onshore growth in 2022 to come from the Permian. However, cost of capital and capital allocation policies are expected to continue to force operators to be disciplined in their spending. While we expect new activity to generally be reduced in 2021, the impact from these events on existing production of crude oil and natural gas, however, is far less certain. Variables such as takeaway capacity, flaring considerations, reservoir pressure and flow rates, high switching costs associated with large horsepower compressors (borne by our customers), and specific company dynamics may all factor into producers’ decisions with respect to their existing production. For example, as wells age, and the reservoir pressures naturally continue to decline, more horsepower may be required to meet the customer’s operational needs. In contrast, small horsepower gas lift applications have historically been more susceptible to commodity price swings, and we have experienced, and may continue to experience, some pressure on service rates and utilization in small horsepower gas lift applications. We cannot predict with reasonable certainty the effect on utilization of our assets servicing existing production in these regions. Unlike crude oil, natural gas production and prices have been influenced by different drivers over the recent past, as there is no OPEC+ equivalent in the global natural gas market and therefore the price of natural gas is generally determined by market forces of supply and demand rather than by a centralized market coordinator. Over the past several years, increased gas production in the U.S. driven by large volumes of gas produced from shale sources has been a main driver of an overall drop in natural gas prices. This sustained low natural gas price environment has helped create relatively resilient baseload demand for natural gas for domestic use in power generation and for industrial purposes such as chemical plants and other types of manufacturing. Also, the development of long-term export infrastructure has continued to occur alongside the low natural gas price environment and the U.S. became a net exporter of natural gas into global markets in 2017. For example, while the EIA expects a decline in natural gas production for 2021 due to a decrease in the usage of natural gas in the electric power generation sector, as a result of relatively higher natural gas prices (versus coal) and increased power generation from renewables, these decreases are expected to be partially offset by other uses, including increased liquefied natural gas exports as well as increased pipeline exports to Mexico. While the EIA expects an overall decline in natural gas production in 2021, monthly production is expected to bottom out in March 2021 and then increase through the rest of 2021, followed by continued increase in 2022. We expect the baseload natural gas demand previously described will continue to support long-term domestic natural gas production. In addition to the relatively stable supply, demand and price fundamentals of natural gas, we believe that the geographic diversity and portability of our assets should help mitigate the impact of market volatility or regional uncertainty. While reduced production of associated gas impacted demand for our services in certain regions beginning in the first quarter of 2020, such reduction in production had a positive impact on both natural gas prices as well as the utilization of our assets in other regions primarily tied to natural gas prospects, such as the Marcellus, Utica and Haynesville shales. Given these producing regions primarily contain natural gas, if natural gas prices remain resilient we believe it is reasonable to expect that these areas could see additional capital inflows to take advantage of relatively more attractive economics, which could increase demand for our services in these shales. The design flexibility of our compression units allow us to make rapid reconfigurations and relocate units to these areas. On the whole, we believe the longer-term outlook for natural gas fundamentals remains positive, as market signs, including natural gas futures market, point to a more balanced gas market through 2021. In summary, while the outlook for commodity prices stabilized over the course of 2020, continued uncertainty with respect to demand could have a varying impact on our business. Whereas several factors, including uncertain future demand, caused volatility in crude oil prices during 2020, on the natural gas side, relatively more moderate demand destruction coupled with associated gas production decreases have in part helped to support natural gas prices. The overall outlook for our compression services will depend, in part, on the strength and duration of recovery in the commodity markets, and we believe as natural gas experienced a recovery more quickly than crude oil, the continued market dynamics should help support our business activities and overall utilization and pricing. 44 Table of Contents While we anticipate that the combination of commodity prices and demand may likely have an impact on activity levels in both the upstream and midstream sectors, we cannot predict the ultimate magnitude of that impact on our business and expect it to be varied across our operations, depending on the region, customer, nature of compression application, contract term and other factors. We believe our customers’ mid- to long-term expectations regarding commodity prices and the cost they would incur to return our large horsepower equipment will provide an incentive for our customers to keep our equipment in the field following expiration of the primary term, whereas we believe there is likely to be continued pressure on utilization and pricing with respect to our smaller horsepower equipment. 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. COVID-19 Update Beginning in the first quarter of 2020, the COVID-19 pandemic prompted several states and municipalities in which we operate to take extraordinary and wide-ranging actions to contain and combat the outbreak and spread of the virus, including mandates for many individuals to substantially restrict daily activities and for many businesses to curtail or cease normal operations. These mandates and restrictions have varied across jurisdictions and, over time, have been rescinded and reinstated as the severity of the pandemic fluctuated. For as long as COVID-19 continues or worsens, governments may impose additional similar restrictions or reinstate previously lifted ones. To date, our field operations have continued largely uninterrupted as the U.S. Department of Homeland Security designated our industry part of our country’s critical infrastructure. Thus far, remote work and other COVID-19 related conditions have not significantly impacted our ability to maintain operations or caused us to incur significant additional expenses; however, we are unable to predict the duration or ultimate impact of current and potential future COVID-19 mitigation measures. 45 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, Percent 2020 2019 Change Fleet horsepower (at period end) (1) 3,726,181 3,682,968 1.2 % Total available horsepower (at period end) (2) 3,726,181 3,709,468 0.5 % Revenue generating horsepower (at period end) (3) 2,997,262 3,310,024 (9.4) % Average revenue generating horsepower (4) 3,139,732 3,279,374 (4.3) % Average revenue per revenue generating horsepower per month (5) $ 16.71 $ 16.65 0.4 % Revenue generating compression units (at period end) 3,968 4,559 (13.0) % Average horsepower per revenue generating compression unit (6) 746 720 3.6 % Horsepower utilization (7): At period end 82.8 % 93.7 % (11.6) % Average for the period (8) 86.8 % 94.1 % (7.8) % ________________________ (1) Fleet horsepower is horsepower for compression units that have been delivered to us (and excludes units on order). (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, 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 80.4% and 89.9% at December 31, 2020 and 2019, 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 84.5% and 89.8% for the years ended December 31, 2020 and 2019, respectively. The 1.2% increase in fleet horsepower as of December 31, 2020 compared to December 31, 2019 was attributable to compression units added to our fleet primarily for specific customer demand for our compression services, partially offset by compression units impaired during the current period. The 9.4% decrease in revenue generating horsepower as of December 31, 2020 compared to December 31, 2019 was due to returns of compression units from our customers which also caused a 13.0% decrease in revenue generating compression units over the same period. The returns of compression units from our customers are primarily due to a decrease in demand for compression services driven by a decline in U.S. crude oil and natural gas activity. The 3.6% increase in average horsepower per revenue generating compression unit was driven primarily by the composition of compression unit returns. The 0.4% increase in average revenue per revenue generating horsepower per month for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to contracts on new compression units and selective price increases on our existing large horsepower fleet, partially offset by reduced pricing in our small horsepower fleet. Horsepower utilization decreased to 82.8% as of December 31, 2020 compared to 93.7% as of December 31, 2019. The 11.6% decrease in horsepower utilization is primarily due to (1) a 10.8% increase in our idle horsepower from compression units returned to us and (2) a 2.0% decrease in horsepower that is on-contract or pending-contract but not yet active. Average 46 Table of Contents horsepower utilization decreased to 86.8% during the year ended December 31, 2020 compared to 94.1% during the year ended December 31, 2019. The 7.8% decrease in average horsepower utilization is primarily due to (1) a 6.9% increase in our average idle horsepower from compression units returned to us and (2) a 3.0% decrease in horsepower that is on-contract or pending-contract but not yet active. The decreases in period end and average horsepower utilization are primarily due to a decrease in demand for compression services driven by a decline in U.S. crude oil and natural gas activity. Horsepower utilization based on revenue generating horsepower and fleet horsepower decreased to 80.4% as of December 31, 2020 compared to 89.9% as of December 31, 2019. The 10.6% decrease in horsepower utilization based on revenue generating horsepower as of December 31, 2020 was primarily attributable to an increase in our idle horsepower from compression units returned to us. Average horsepower utilization based on revenue generating horsepower and fleet horsepower decreased to 84.5% for the year ended December 31, 2020 compared to 89.8% for the year ended December 31, 2019. The 5.9% decrease in average horsepower utilization based on revenue generating horsepower for the year ended December 31, 2020 was primarily attributable to an increase in our average idle horsepower from compression units returned to us. The decreases in period end and average horsepower utilization based on revenue generating horsepower and fleet horsepower are primarily due to a decrease in demand for compression services driven by a decline in U.S. crude oil and natural gas activity. Financial Results of Operations Year ended December 31, 2020 compared to the year ended December 31, 2019 The following table summarizes our results of operations for the periods presented (dollars in thousands): Year Ended December 31, Percent 2020 2019 Change Revenues: Contract operations $ 644,194 $ 664,162 (3.0) % Parts and service 11,117 14,236 (21.9) % Related party 12,372 19,967 (38.0) % Total revenues 667,683 698,365 (4.4) % Costs and expenses: Cost of operations, exclusive of depreciation and amortization 205,939 227,303 (9.4) % Depreciation and amortization 238,968 231,447 3.2 % Selling, general and administrative 59,981 64,397 (6.9) % Loss on disposition of assets 146 940 (84.5) % Impairment of compression equipment 8,090 5,894 37.3 % Impairment of goodwill 619,411 — * Total costs and expenses 1,132,535 529,981 * Operating income (loss) (464,852) 168,384 * Other income (expense): Interest expense, net (128,633) (127,146) 1.2 % Other 86 80 7.5 % Total other expense (128,547) (127,066) 1.2 % Net income (loss) before income tax expense (593,399) 41,318 * Income tax expense 1,333 2,186 (39.0) % Net income (loss) $ (594,732) $ 39,132 * ________________________ * Not meaningful. Contract operations revenue . The $20.0 million decrease in contract operations revenue for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to a decline in demand for compression services driven by a decrease in U.S. crude oil and natural gas activity. This decline in demand resulted in a 4.3% decrease in average revenue generating horsepower for the year ended December 31, 2020 compared to the year ended December 31, 2019, partially offset by a 0.4% increase in average revenue per revenue generating horsepower per month which increased to $16.71 for the year ended December 31, 2020 compared to $16.65 for the year ended December 31, 2019. Our contract operations revenue was not 47 Table of Contents materially impacted by any renegotiations of our contracts during the period with our customers. Additionally, average revenue per revenue generating horsepower per month associated with our compression services provided on a month-to-month basis did not significantly differ 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 $3.1 million decrease in parts and service revenue for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily attributable to a reduction in maintenance work performed on units at our customers’ locations that are outside the scope of our core maintenance activities and offered as a courtesy to our customers, and freight and crane charges that are directly reimbursable by customers. Demand for retail parts and services fluctuates from period to period based on the varying needs of our customers. Related party revenue. Related party revenue was earned through related party transactions in the ordinary course of business with various affiliated entities of ETO. The $7.6 million decrease in related party revenue for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily attributable to a decrease in parts and service revenue, as well as a decrease in contract operations revenue due to the expiration of contracts with various affiliated entities of ETO. Cost of operations, exclusive of depreciation and amortization. The $21.4 million decrease in cost of operations for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to (1) an $11.5 million decrease in direct expenses, such as parts and fluids expenses, (2) a $6.2 million decrease in direct labor expenses, (3) a $4.6 million decrease in retail parts and services expenses, which had a corresponding decrease in parts and service revenue, (4) a $3.1 million decrease in expenses related to our vehicle fleet and (5) a $1.7 million decrease in training and other indirect expenses. The decreases in parts, fluids, direct labor, vehicle expenses, training and other indirect expenses are primarily driven by the decrease in average revenue generating horsepower and reduced headcount during the current period. The decreases were partially offset by (6) a $5.1 million increase in ad valorem tax expenses due primarily to refunds received during the prior period. Depreciation and amortization expense . The $7.5 million increase in depreciation and amortization expense for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily related to compression units and other capital expenditures placed in service during 2019, to meet then existing demand by customers, that have a full year of depreciation expense recorded in 2020. Selling, general and administrative expense . The $4.4 million decrease in selling, general and administrative expense for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to (1) a $2.4 million decrease in employee-related expenses, (2) a $2.4 million decrease in general corporate expenses, (3) a $2.4 million decrease in unit-based compensation expense and (4) a $1.1 million decrease in third-party professional fees. These decreases were offset by (5) a $2.7 million increase in the provision for expected credit losses and (6) a $1.6 million increase in severance charges. The decreases in employee-related expenses, general corporate expenses and third-party professional fees are related to reduced headcount and cost saving measures. The decrease in unit-based compensation expense is primarily due to the decrease in our unit price in the current period and the related mark-to-market change to our unit-based compensation liability. The change to the provision for expected credit losses is related to the potential negative impact to our customers of low crude oil prices driven by decreased demand due to the COVID-19 pandemic and the global oversupply of crude oil during the current period. The increase in severance charges is primarily related to the departure of one of our executives during the current period. Impairment of compression equipment . The $8.1 million and $5.9 million impairments of compression equipment during the years ended December 31, 2020 and 2019, respectively, were primarily the result of our evaluations of the future deployment of our idle fleet under current market conditions. The primary causes for these impairments were: (i) units were not considered marketable in the foreseeable future, (ii) units were subject to excessive maintenance costs or (iii) units were unlikely to be accepted by customers due to certain performance characteristics of the unit, such as the inability to meet current quoting criteria without excessive retrofitting costs. These compression units were written down to their respective estimated salvage values, if any. As a result of our evaluations during the years ended December 31, 2020 and 2019, we determined to retire 37 and 33 compression units, respectively, with a total of approximately 15,000 and 11,000 horsepower, respectively, that had been previously used to provide compression services in our business. Impairment of goodwill. During the first quarter of 2020 certain potential impairment indicators were identified, specifically (i) the decline in the market price of our common units, (ii) the decline in global commodity prices, and (iii) the COVID-19 pandemic; which together indicated the fair value of the reporting unit was less than its carrying amount as of 48 Table of Contents March 31, 2020. We performed a quantitative goodwill impairment test as of March 31, 2020 and determined fair value using a weighted combination of the income approach and the market approach and, as a result, recognized a goodwill impairment of $619.4 million for the year ended December 31, 2020. No impairment was recorded for the year ended December 31, 2019. Interest expense, net . The $1.5 million increase in interest expense, net for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to a full year of interest expense incurred in the current period on the Senior Notes 2027 issued in March 2019, partially offset by reduced borrowings and lower weighted average interest rates under the Credit Agreement. The weighted average interest rate applicable to borrowings under the Credit Agreement was 3.27% for the year ended December 31, 2020 compared to 4.84% for the year ended December 31, 2019. Average outstanding borrowings under the Credit Agreement were $455.7 million for the year ended December 31, 2020 compared to $493.3 million for the year ended December 31, 2019. Income tax expense. The $0.9 million decrease in income tax expense for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily related to deferred taxes associated with the Texas Margin Tax. Other Financial Data The following table summarizes other financial data for the periods presented (dollars in thousands): Year Ended December 31, Percent Other Financial Data: (1) 2020 2019 Change Gross margin $ 222,776 $ 239,615 (7.0) % Adjusted gross margin $ 461,744 $ 471,062 (2.0) % Adjusted gross margin percentage (2) 69.2 % 67.5 % 2.5 % Adjusted EBITDA $ 413,898 $ 419,640 (1.4) % Adjusted EBITDA percentage (2) 62.0 % 60.1 % 3.2 % DCF $ 220,766 $ 221,868 (0.5) % DCF Coverage Ratio 1.09 x 1.13 x (3.5) % Cash Coverage Ratio 1.10 x 1.14 x (3.5) % ________________________ (1) Adjusted gross margin, Adjusted EBITDA, DCF, DCF Coverage Ratio and Cash 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 under the caption “Non-GAAP Financial Measures” in Part II, Item 6 “Selected Financial Data”. (2) Adjusted gross margin percentage and Adjusted EBITDA percentage are calculated as a percentage of revenue. Gross margin. The $16.8 million decrease in gross margin for the year ended December 31, 2020 compared to the year ended December 31, 2019 was due to (1) a $30.7 million decrease in revenues and (2) a $7.5 million increase in depreciation and amortization, offset by (3) a $21.4 million decrease in cost of operations, exclusive of depreciation and amortization. Adjusted gross margin. The $9.3 million decrease in Adjusted gross margin for the year ended December 31, 2020 compared to the year ended December 31, 2019 was due to a $30.7 million decrease in revenues, offset by a $21.4 million decrease in cost of operations, exclusive of depreciation and amortization. Adjusted EBITDA. The $5.7 million decrease in Adjusted EBITDA for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to a $9.3 million decrease in Adjusted gross margin, partially offset by a $3.2 million decrease in selling, general and administrative expenses, excluding unit-based compensation expense, severance charges and transaction expenses. DCF. The $1.1 million decrease in DCF during the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to (1) a $9.3 million decrease in Adjusted gross margin and (2) a $0.7 million increase in cash interest expense, net, partially offset by (3) a $6.3 million decrease in maintenance capital expenditures and (4) a $3.2 million decrease in selling, general and administrative expenses, excluding unit-based compensation expense, severance charges and transaction expenses. 49 Table of Contents Coverage Ratios . The decreases in DCF Coverage Ratio and Cash Coverage Ratio for the year ended December 31, 2020 compared to the year ended December 31, 2019 were primarily due to additional distributions in 2020 due to the conversion of 6,397,965 Class B Units, which did not participate in distributions, to common units on a one-for-one basis on July 30, 2019. Liquidity and Capital Resources Overview We operate in a capital-intensive industry, and our primary liquidity needs are to finance the purchase of additional compression units and make other capital expenditures, service our debt, fund working capital, and pay distributions. 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 typically utilize cash generated by operating activities and, where necessary, borrowings under the Credit Agreement to service our debt, fund working capital, fund our estimated expansion capital expenditures, fund our maintenance capital expenditures and pay distributions to our unitholders. In response to current market conditions, we have reduced our planned capital spending significantly for 2021. However, if market conditions related to COVID-19 persist, this could eventually reduce our cash generated by operating activities and increase our leverage. Covenants in the Credit Agreement and other debt instruments require that we maintain certain leverage ratios, and if we predict that we may violate those covenants in the future we could: (i) delay discretionary capital spending and reduce operating expenses; (ii) request an amendment to the Credit Agreement; (iii) reduce or suspend distributions to our unitholders; or (iv) issue equity securities, including under the DRIP. The Credit Agreement was amended on August 3, 2020 to amend, among other things, the requirements of certain covenants and the date on which certain covenants in the Credit Agreement must be met beginning on the Amendment Effective Date until the last day of the fiscal quarter ending December 31, 2021. Please see “Revolving Credit Facility” below for additional information regarding the amendment. 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 have consisted primarily of, and we anticipate that our capital requirements will continue to consist primarily 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 were not currently 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, 2020 and 2019 were $23.3 million and $29.6 million, respectively. We currently plan to spend approximately $22.0 million in maintenance capital expenditures during 2021, including parts consumed from inventory. Without giving effect to any equipment we may acquire pursuant to any future acquisitions, we currently have budgeted between $30.0 million and $40.0 million in expansion capital expenditures during 2021. Our expansion capital expenditures for the years ended December 31, 2020 and 2019 were $95.6 million and $170.3 million, respectively. 50 Table of Contents Cash Flows The following table summarizes our sources and uses of cash for the years ended December 31, 2020 and 2019 (in thousands): Year Ended December 31, 2020 2019 Net cash provided by operating activities $ 293,198 $ 300,580 Net cash used in investing activities (105,099) (144,490) Net cash used in financing activities (188,107) (156,179) Net cash provided by operating activities . The $7.4 million decrease in net cash provided by operating activities for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to a $5.3 million decrease in net income, as adjusted for non-cash items, and changes in other working capital. Net cash used in investing activities . The $39.4 million decrease in net cash used in investing activities for the year ended December 31, 2020 compared to the year ended December 31, 2019 was due to (1) a $62.1 million decrease in capital expenditures for purchases of new compression units, related equipment and reconfiguration costs, offset by (2) a $19.8 million decrease in proceeds from disposition of property and equipment and (3) a $2.9 million decrease in insurance proceeds received for compression units previously damaged. Net cash used in financing activities . The $31.9 million increase in net cash used in financing activities for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to (1) a $32.1 million decrease in net borrowings and (2) a $10.5 million increase in cash distributions paid on common units primarily due to the conversion of 6,397,965 Class B Units, which did not participate in distributions, to common units on a one-for-one basis on July 30, 2019. These changes were partially offset by a decrease in financing costs of $9.8 million due primarily to the issuance of the Senior Notes 2027 in March 2019. Revolving Credit Facility As of December 31, 2020, we were in compliance with all of our covenants under the Credit Agreement. As of December 31, 2020, we had outstanding borrowings under the Credit Agreement of $473.8 million, $1.1 billion of borrowing base availability and, subject to compliance with the applicable financial covenants, available borrowing capacity of $284.2 million. As of February 11, 2021, we had outstanding borrowings under the Credit Agreement of $498.2 million. On the Amendment Effective Date, we amended the Credit Agreement to, among other things, increase the maximum funded debt to EBITDA ratio to (i) 5.75 to 1.00 for the fiscal quarters ending September 30, 2020 and December 31, 2020, (ii) 5.50 to 1.00 for the fiscal quarters ending March 31, 2021 and June 30, 2021 and (iii) 5.25 to 1.00 for the fiscal quarters ending September 30, 2021 and December 31, 2021 (reverting back to 5.00 to 1.00 after the Covenant Relief Period). In addition, the amendment provides that the 0.50 increase in maximum funded debt to EBITDA ratio applicable to certain future acquisitions (for the six consecutive month period in which any such acquisition occurs) is only available beginning with the fiscal quarter ending September 30, 2021, and in any case shall not increase the maximum funded debt to EBITDA ratio above 5.50 to 1.00. The amendment also provides that, during the Covenant Relief Period, the availability requirement in order to make restricted payments from capital contributions and from available cash are each increased from $100 million to $250 million and the availability requirement in order to make prepayments of our senior notes, any subordinated indebtedness or any other indebtedness for borrowed money is increased from $100 million to $250 million. In addition, during the Covenant Relief Period, the applicable margin for Eurodollar borrowings is increased from a range of 2.00% – 2.75% to a range of 2.25% – 3.00%. The amendment further provides that the Partnership becomes guarantor of the obligations of all other guarantors under the Credit Agreement. We expect to remain in compliance with our covenants under the Credit Agreement throughout 2021. 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 debt and equity securities in conjunction with the acquisition of another business; 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 obtain an equity infusion pursuant to the terms of the Credit Agreement. For a more detailed description of the Credit Agreement including the covenants and restrictions contained therein, please refer to Note 10 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”. 51 Table of Contents Senior Notes As of December 31, 2020, 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, please refer to Note 10 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”. DRIP During the years ended December 31, 2020 and 2019, distributions of $1.9 million and $1.0 million, respectively, were reinvested under the DRIP resulting in the issuance of 188,695 and 60,584 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. Total Contractual Cash Obligations The following table summarizes our total contractual cash obligations as of December 31, 2020 (in thousands): Payments Due by Period Contractual Obligations Total Less than 1 year 1 - 3 years 3 - 5 years More than 5 years Long-term debt (1) $ 1,948,810 $ — $ 473,810 $ — $ 1,475,000 Interest on long-term debt obligations (2) 676,030 119,607 225,563 202,813 128,047 Operating and finance lease obligations (3) 31,235 4,808 8,253 6,910 11,264 Total contractual cash obligations $ 2,656,075 $ 124,415 $ 707,626 $ 209,723 $ 1,614,311 ________________________ (1) We assumed that the amount outstanding under the Credit Agreement at December 31, 2020 would be repaid in April 2023, the maturity date of the facility. The $725.0 million aggregate principal amount of our Senior Notes 2026 outstanding is due April 1, 2026, and the $750.0 million aggregate principal amount of our Senior Notes 2027 outstanding is due September 1, 2027. (2) Represents future interest payments under the Credit Agreement based on outstanding borrowings as of December 31, 2020, and the effective interest rate and unused commitment fee as of December 31, 2020 of 2.95% and 0.375%, respectively, and interest payments on our $1.5 billion aggregate principal amount of the Senior Notes. (3) Represents commitments for future minimum lease payments on noncancelable operating and finance leases. Effects of Inflation . Our revenues and results of operations have not been materially impacted by inflation and changing prices in the past two fiscal years. Off-Balance Sheet Arrangements We have no off-balance sheet financing activities. Please refer to Note 17 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” included in this report for a description of our commitments and contingencies. Critical Accounting Policies and Estimates The discussion and analysis of our financial condition and results of operations is based upon 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 various other assumptions we believe to be reasonable under the circumstances. On an ongoing basis, 52 Table of Contents we evaluate our estimates; however, actual results may differ from these estimates under different assumptions or conditions. The accounting policies that we believe require management’s most difficult, subjective or complex judgments and are the most critical to its reporting of results of operations and financial position are as follows: Revenue Recognition We recognize revenue when obligations under the terms of a contract with our customer are satisfied; generally this occurs with the transfer of our services or goods. Revenue is measured as the amount of consideration we expect to receive in exchange for providing services or transferring goods. Sales taxes incurred on behalf of, and passed through to, customers are excluded from revenue. Incidental items, if any, that are immaterial in the context of the contract are recognized as expense. Contract operations revenue Revenue from contracted compression, station, gas treating and maintenance services is recognized ratably under our fixed-fee contracts over the term of the contract as services are provided to our customers. Initial contract terms typically range from six months to five years, however we usually continue to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. We primarily enter into fixed-fee contracts whereby our customers are required to pay our monthly fee even during periods of limited or disrupted throughput. Services are generally billed monthly, one month in advance of the commencement of the service month, except for certain customers who are billed at the beginning of the service month, and payment is generally due 30 days after receipt of our invoice. Amounts invoiced in advance are recorded as deferred revenue until earned, at which time they are recognized as revenue. The amount of consideration we receive and revenue we recognize is based upon the fixed fee rate stated in each service contract. Retail parts and services revenue Retail parts and services revenue is earned primarily on freight and crane charges that are directly reimbursable by our customers and maintenance work on units at our customers’ locations that are outside the scope of our core maintenance activities. Revenue from retail parts and services is recognized at the point in time the part is transferred or service is provided and control is transferred to the customer. At such time, the customer has the ability to direct the use of the benefits of such part or service after we have performed our services. We bill upon completion of the service or transfer of the parts, and payment is generally due 30 days after receipt of our invoice. The amount of consideration we receive and revenue we recognize is based upon the invoice amount. There are typically no material obligations for returns, refunds, or warranties. Our standard contracts do not usually include material variable or non-cash consideration. Business Combinations and Goodwill Goodwill acquired in connection with business combinations represents the excess of consideration over the fair value of net assets acquired. Certain assumptions and estimates are employed in determining the fair value of assets acquired and liabilities assumed. Goodwill is not amortized, but is reviewed for impairment annually based on the carrying values as of October 1, or more frequently if impairment indicators arise that suggest the carrying value of goodwill may not be recovered. Goodwill – Impairment Assessments We evaluate goodwill for impairment annually on October 1 and whenever events or changes indicate that it is more likely than not that the fair value of our single business reporting unit could be less than its carrying value (including goodwill). The timing of the annual test may result in charges to our statement of operations in our fourth fiscal quarter that could not have been reasonably foreseen in prior periods. We estimate the fair value of our reporting unit based on a number of factors, including the potential value we would receive if we sold the reporting unit, enterprise value, discount rates and projected cash flows. Estimating projected cash flows requires us to make certain assumptions as it relates to future operating performance. When considering operating performance, various factors are considered such as current and changing economic conditions and the commodity price environment, among others. Due to the imprecise nature of these projections and assumptions, actual results can, and often do, differ from our estimates. During the first quarter of 2020 certain potential impairment indicators were identified, specifically (i) the decline in the market price of our common units, (ii) the decline in global commodity prices and (iii) the COVID-19 pandemic; which together indicated the fair value of the reporting unit was less than its carrying amount as of March 31, 2020. We performed a quantitative goodwill impairment test as of March 31, 2020 and determined fair value using a weighted combination of the income approach and the market approach. Determining fair value of a reporting unit requires judgment and 53 Table of Contents use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, EBITDA margins, weighted average costs of capital and future market conditions, among others. We believe the estimates and assumptions used were reasonable and based on available market information, but variations in any of the assumptions could have resulted in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the income approach, we determined fair value based on estimated future cash flows, including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflects the overall level of inherent risk of the Partnership. Cash flow projections were derived from four-year operating forecasts plus an estimate of later period cash flows, all of which were developed by management. Subsequent period cash flows were developed using growth rates that management believed were reasonably likely to occur. Under the market approach, we determined fair value by applying valuation multiples of comparable publicly-traded companies to the projected EBITDA of the Partnership and then averaging that estimate with similar historical calculations using a three-year average. In addition, we estimated a reasonable control premium representing the incremental value that would accrue to us if we were to be acquired. Based on the quantitative goodwill impairment test described above, our carrying amount exceeded fair value and as a result, we recognized a goodwill impairment of $619.4 million for the year ended December 31, 2020. As of October 1, 2019, we performed a qualitative assessment of relevant events and circumstances potentially indicating the likelihood of goodwill impairment. The qualitative assessment included weighting such factors as (i) macroeconomic conditions, (ii) industry and market considerations, (iii) cost factors, (iv) overall financial performance of the reporting unit, (v) other relevant entity-specific events, and (vi) consideration of whether there was a sustained decrease in the price of our units. Upon completion of our qualitative assessment, we concluded that it was not more likely than not that the fair value of our single reporting unit was less than its carrying value and that our goodwill was not impaired for the year ended December 31, 2019. 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 could reasonably 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 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, 2020 and 2019, we evaluated the future deployment of our idle fleet under current market conditions and determined to retire 37 and 33 compressor units, respectively, for a total of approximately 15,000 and 11,000 horsepower, respectively, that were previously used to provide compression services in our business. As a result, we recorded impairments of compression equipment of $8.1 million and $5.9 million for the years ended December 31, 2020 and 2019, respectively. The primary causes for these impairments were: (i) units were not considered marketable in the foreseeable future, (ii) units were subject to excessive maintenance costs or (iii) units were unlikely to be accepted by customers due to certain performance characteristics of the unit, such as the inability to meet current quoting criteria without excessive retrofitting costs. These compression units were written down to their respective estimated salvage values, if any. Allowance for Credit Losses We maintain an allowance for credit losses for our two financial assets, (i) trade accounts receivable and (ii) net investment in lease related to our sales-type lease, based on specific customer collection issues and historical experience. 54 Table of Contents Our determination of the allowance for credit losses requires us to make estimates and judgments regarding our customers’ ability to pay amounts due and is the same process for both of our financial assets as they have similar risk characteristics. We continuously evaluate the financial strength of our customers based on collection experience, the overall business climate in which our customers operate and specific identification of customer credit losses and make adjustments to the allowance as necessary. Our evaluation of our customers’ financial strength is based on the aging of their respective receivables balance, customer correspondence, financial information and third-party credit ratings. Our evaluation of the business climate in which our customers operate is based on a review of various publicly available materials regarding our customers’ industries, including the solvency of various companies in the industry. Recent Accounting Pronouncements Please see Part II, Item 8 “Financial Statements and Supplementary Data”, Note 2 for discussion on the adoption of Accounting Standards Update 2016-13 Financial Instruments – Credit Losses (“Topic 326”): Measurement of Credit Losses on Financial Instruments and Note 18 for other specific recent accounting pronouncements affecting us.