Following the transactions described in further detail below, CDM Resource
Management LLC ("CDM Resource") and CDM Environmental & Technical Services LLC
("CDM E&T"), which together represent the CDM Compression Business (the "USA
Compression Predecessor"), has been determined to be the historical predecessor
of USA Compression Partners, LP (the "Partnership") for financial reporting
purposes. The USA Compression Predecessor is considered the predecessor of the
Partnership because Energy Transfer Equity LP ("ETE"), through its wholly owned
subsidiary Energy Transfer Partners, L.L.C., ("ETP LLC") controlled the USA
Compression Predecessor prior to the transactions described below and obtained
control of the Partnership through its acquisition of USA Compression GP, LLC,
the general partner of the Partnership (the "General Partner").
The closing of the Transactions occurred on April 2, 2018 (the "Transactions
Date") and has been reflected in the consolidated financial statements of the
Partnership.
In October 2018, ETE and Energy Transfer Partners, L.P. ("ETP") completed the
merger of ETP with a wholly owned subsidiary of ETE in a unit-for-unit exchange
(the "ETE Merger"). Following the closing of the ETE Merger, ETE changed its
name to "Energy Transfer LP" ("ET LP") and ETP changed its name to "Energy
Transfer Operating, L.P." ("ETO"). Upon the closing of the ETE Merger, ETE
contributed to ETO 100% of the limited liability company interests in the
General Partner. References herein to "ETO" refer to ETP for periods prior to
the ETE Merger and ETO following the ETE Merger, and references to "ET LP" refer
to ETE for periods prior to the ETE Merger and ET LP following the ETE Merger.
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". All
references in this section to the USA Compression Predecessor, as well as the
terms "our," "we," "us" and "its" refer to the USA Compression Predecessor when
used in a historical context or in reference to the periods prior to the
Transactions Date, unless the context otherwise requires or where otherwise
indicated. All references in this section to the Partnership, as well as the
terms "our," "we," "us" and "its" refer to USA

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Compression Partners, LP, together with its consolidated subsidiaries, including
the USA Compression Predecessor, when used in the present or future tense and
for periods subsequent to the Transactions Date, unless the context otherwise
requires or where otherwise indicated.
Discussion and analysis of our operating highlights and financial results of
operations for the year ended December 31, 2018 compared to the year ended
December 31, 2017 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" in our Annual Report on
Form 10-K filed for the year ended December 31, 2018 with the SEC on February
19, 2019.
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 with 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 U.S. Energy Information Administration ("EIA"), the
production and transportation volumes of these shale plays, in aggregate, are
expected to increase over the long term due to the comparatively attractive
economic returns versus returns achieved in many conventional basins.
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 flexibility of 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 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
2027 Senior Notes Issuance and Exchange
On March 7, 2019, the Partnership and its wholly owned finance subsidiary, USA
Compression Finance Corp. ("Finance Corp") co-issued $750.0 million aggregate
principal amount of senior notes due on September 1, 2027 (the "Senior Notes
2027"). The Senior Notes 2027 accrue interest from March 7, 2019 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, with the first such payment having
occurred on September 1, 2019.
On December 18, 2019, the Partnership closed an exchange offer whereby holders
of the Senior Notes 2027 exchanged all of the Senior Notes 2027 for an
equivalent amount of senior notes ("Exchange Notes 2027") registered under the
Securities Act of 1933, as amended ("Securities Act").  The Exchange Notes 2027
are substantially identical to the Senior Notes 2027, except that the Exchange
Notes 2027 have been registered with the U.S. Securities and Exchange Commission
("SEC") and do not contain the transfer restrictions, restrictive legends,
registration rights or additional interest provisions of the Senior Notes 2027.
2018 CDM Acquisition and Related Transactions
CDM Acquisition and Issuance of Class B Units
On the Transactions Date, we consummated the transactions contemplated by the
Contribution Agreement dated January 15, 2018, pursuant to which, among other
things, we acquired all of the issued and outstanding membership interests of
the USA Compression Predecessor from ETO (the "CDM Acquisition") in exchange for
aggregate consideration of approximately $1.7 billion, consisting of (i)
19,191,351 common units representing limited partner interests in us (the
"common units"), (ii) 6,397,965 Class B units representing limited partner
interests in us ("Class B Units") and (iii) $1.2 billion in cash (including
customary closing adjustments). On July 30, 2019, 6,397,965 Class B Units
automatically converted into common units on a one-for-one basis, resulting in
the issuance of 6,397,965 common units to ETO. Following the conversion, there
are no longer Class B Units outstanding.

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General Partner Purchase Agreement
On the Transactions Date, and in connection with the closing of the CDM
Acquisition, we consummated the transactions contemplated by the Purchase
Agreement dated January 15, 2018, by and among ET LP, ETP LLC, USA Compression
Holdings, LLC ("USA Compression Holdings") and, solely for certain purposes
therein, R/C IV USACP Holdings, L.P. and ETO, pursuant to which, among other
things, ET LP acquired from USA Compression Holdings (i) all of the outstanding
limited liability company interests in the General Partner and (ii) 12,466,912
common units for cash consideration paid by ET LP to USA Compression Holdings
equal to $250.0 million (the "GP Purchase"). Upon the closing of the ETE Merger,
ET LP contributed all of the interests in the General Partner and the 12,466,912
common units to ETO.
Equity Restructuring Agreement
On the Transactions Date, and in connection with the closing of the CDM
Acquisition, we consummated the transactions contemplated by the Equity
Restructuring Agreement dated January 15, 2018 (the "Equity Restructuring
Agreement"), pursuant to which, among other things, the Partnership, the General
Partner and ET LP agreed to cancel the Partnership's Incentive Distribution
Rights ("IDRs") and convert the General Partner's interest into a non-economic
general partner interest, in exchange for the Partnership's issuance of
8,000,000 common units to the General Partner (the "Equity Restructuring"). In
addition, at any time after one year following the Transactions Date, ET LP has
the right to contribute (or cause any of its subsidiaries to contribute) to us
all of the outstanding equity interests in any of its subsidiaries that owns the
general partner interest in us in exchange for $10.0 million (the "GP
Contribution"); provided that the GP Contribution will occur automatically if at
any time following the Transactions Date (i) ET LP or one of its subsidiaries
(including ETO) owns, directly or indirectly, the general partner interest in us
and (ii) ET LP and its subsidiaries (including ETO) collectively own less than
12,500,000 of our common units.
The CDM Acquisition, GP Purchase and Equity Restructuring are collectively
referred to as the "Transactions."
Series A Preferred Unit and Warrant Private Placement
On the Transactions Date, we completed a private placement of $500 million in
the aggregate of (i) newly authorized and established Series A Preferred Units
representing limited partner interests in us (the "Preferred Units") and
(ii) warrants to purchase common units (the "Warrants") pursuant to a Series A
Preferred Unit and Warrant Purchase Agreement dated January 15, 2018, between
the Partnership and certain investment funds managed or advised by EIG Global
Energy Partners and FS Energy and Power Fund (collectively, the "Preferred
Unitholders"). We issued 500,000 Preferred Units with a face value of $1,000 per
Preferred Unit and issued two tranches of Warrants to the Preferred Unitholders,
which included Warrants to purchase 5,000,000 common units with a strike price
of $17.03 per unit and 10,000,000 common units with a strike price of $19.59 per
unit. The Warrants may be exercised by the holders thereof at any time beginning
April 2, 2019 and before April 2, 2028.
2026 Senior Notes Issuance and Exchange
On March 23, 2018, the Partnership and Finance Corp co-issued $725.0
million aggregate principal amount of senior notes due on April 1, 2026 (the
"Senior Notes 2026"). The Senior Notes 2026 accrue interest from March 23, 2018
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, with the first such
payment having occurred on October 1, 2018.
On January 14, 2019, the Partnership closed an exchange offer whereby holders of
the Senior Notes 2026 exchanged all of the Senior Notes 2026 for an equivalent
amount of senior notes ("Exchange Notes 2026") registered under the Securities
Act. The Exchange Notes 2026 are substantially identical to the Senior Notes
2026, except that the Exchange Notes 2026 have been registered with the SEC and
do not contain the transfer restrictions, restrictive legends, registration
rights or additional interest provisions of the Senior Notes 2026.
Credit Agreement Amendment and Restatement
On the Transactions Date, we entered into the Sixth Amended and Restated Credit
Agreement (the "Credit Agreement") by and among the Partnership, as borrower,
USAC OpCo 2, LLC, USAC Leasing 2, LLC, USA Compression Partners, LLC, USAC
Leasing, LLC, CDM Resource, CDM E&T and Finance Corp, the lenders party thereto
from time to time, JPMorgan Chase Bank, N.A., as agent and a letter of credit
("LC") issuer, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Regions Capital
Markets, a division of Regions Bank, RBC Capital Markets and Wells Fargo Bank,
N.A., as joint lead arrangers and joint book runners, Barclays Bank PLC, Regions
Bank, RBC Capital Markets and Wells Fargo Bank, N.A., as syndication agents, and
MUFG Union Bank, N.A., SunTrust Bank and The Bank of Nova Scotia, as senior
managing agents. The Credit Agreement amended and restated

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that certain Fifth Amended and Restated Credit Agreement, dated as of December
13, 2013, as amended (the "Fifth A&R Credit Agreement").
The Credit Agreement amended the Fifth A&R Credit Agreement to, among other
things, (i) increase the borrowing capacity under the Credit Agreement from $1.1
billion to $1.6 billion (subject to availability under a borrowing base),
(ii) extend the termination date (and the maturity date of the obligations
thereunder) from January 6, 2020 to April 2, 2023, (iii) subject to the terms of
the Credit Agreement, permit up to $400.0 million of future increases in
borrowing capacity, (iv) modify the leverage ratio covenant to be 5.5 to 1.0
through the end of the fiscal quarter ending December 31, 2019, and 5.0 to 1.0
thereafter and (v) increase the applicable margin for eurodollar borrowings to
range from 2.00% to 2.75%, depending on our leverage ratio, all as more fully
set forth in the Credit Agreement.
General Trends and Outlook
Natural gas compression is a critical part of the natural gas value chain,
facilitating the movement of natural gas throughout the domestic pipeline
system. Our business is driven in part by the increasing volumes of natural gas
being produced in this country and the areas and conditions in which it is
produced. Compression is generally required throughout the life of a producing
basin; areas of moderating or declining natural gas production require
compression to achieve minimum pressure to enter gathering and transmission
pipelines. Without compression, natural gas will generally not move through a
pipeline and can thus become stranded in a given area.
A significant amount of our assets are utilized in natural gas infrastructure
applications, primarily in centralized natural gas gathering systems and
processing facilities. Rather than being more closely tied to the wellhead
impact of commodity price variability, these applications generally tend to be
characterized by a long-term investment horizon on the part of our customers; as
such, we have generally experienced stability in rates and higher sustained
utilization rates relative to other businesses more tied to drilling activity
and wellhead economics. In addition to assets utilized in infrastructure
applications, a small portion of our fleet horsepower is used for gas lift
applications in connection with crude oil production using horizontal drilling
techniques.
Increasing levels of domestic natural gas production as a general rule require
more installed compression in order to move the gas through the pipeline system
and to the ultimate end user, whether that user be commercial, industrial or
residential in nature. The EIA's January 2020 Short-Term Energy Outlook ("EIA
Outlook") expects dry natural gas production to increase to 94.7 billion cubic
feet per day ("Bcf/d") in 2020 (an increase of 3% over the record high
production of 92.0 Bcf/d in 2019) and then decline to 94.1 Bcf/d in 2021. The
EIA's expected growth in natural gas production for 2020 is largely in response
to improved drilling efficiency and cost reductions, higher associated gas
production from oil-directed rigs, and increased takeaway pipeline capacity from
the Appalachian and Permian production regions. Forecast natural gas production
growth is also supported by planned expansions in liquefied natural gas ("LNG")
capacity and increased pipeline exports to Mexico. The decline in natural gas
production in 2021 is in response to a forecast of low natural gas spot prices
in 2020 that reduces drilling activity in the Appalachian Basin.
Henry Hub natural gas spot prices averaged $2.57 per million British thermal
units ("MMBtu") in 2019, down from $3.16/MMBtu in 2018. The EIA Outlook expects
Henry Hub prices to decrease to an average of to $2.33/MMBtu in 2020 and then
increase to an average of $2.54/MMBtu in 2021.
Recently, overall domestic natural gas production has increased significantly to
meet the growing demand domestically as well as abroad, through, among other
things, LNG exports. Over the last ten years, the EIA Outlook reports that dry
natural gas production has increased by 63%, or approximately 5% annually. This
increase has caused meaningful demand for our services as operators have built
out the necessary infrastructure to move, process and consume these increased
volumes of natural gas.
While the EIA expects the overall trajectory of natural gas production to
moderate, we believe demand for compression services will continue to increase
because, as high-decline shale wells begin to age and production is tempered,
new sources of natural gas will be required in order to meet demand. Although we
cannot predict any possible changes in demand with reasonable certainty, we
expect demand for our compression services to remain strong throughout 2020.
Particularly in the Permian and Delaware Basins, natural gas tends to be
produced alongside crude oil, and is thus known as "associated" gas. Due to many
factors, the Permian and Delaware Basins have experienced significant activity
levels in recent years, and along with the production of crude oil, the EIA has
reported a 157% increase in associated natural gas produced in those areas since
December 2015 and a 24% increase in December 2019 as compared to December 2018.
Because customers must handle the associated natural gas, compression has been a
critical part of the equation for our customers to be able to produce the
desired crude oil and move it to market. Given the relatively attractive
economics of producing crude oil in the Permian and Delaware Basins, these areas
are expected to continue to be important sources of crude oil, along with the
associated natural gas,

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in the coming years. As crude oil production grows in these areas, there will be
demand for additional compression to handle the associated natural gas.
The EIA Outlook forecasts total U.S. crude oil production to average 13.3
million barrels per day ("bbl/d") in 2020, up 9% from 2019 average production of
12.2 million bbl/d, which was the highest annual average on record. Average
production in 2021 is expected to continue to increase to 13.7 million bbl/d.
Almost all of the production growth within the U.S. is expected to be
attributable to onshore production within the lower 48 states, and particularly
from the Permian and Delaware Basins in Texas and New Mexico, which account for
0.8 million bbl/d and 0.4 million bbl/d of the increases in 2020 and 2021,
respectively. Favorable geology and technological and operational improvements
have allowed the Permian and Delaware Basins to become one of the most prolific
regions for oil production. The EIA Outlook forecasts a slowing rate of
increases in year-over-year crude oil production, primarily as a result of a
decline in the deployment of drilling rigs over the past year, a trend which the
EIA expects will continue through 2020 and into 2021. Despite the decline in the
number of drilling rigs, the EIA forecasts production will continue to grow as
rig efficiency and well-level productivity rise. As crude oil production grows,
we expect natural gas production to grow as well.
For 2020, the EIA's West Texas Intermediate ("WTI") crude oil price forecast
rises by $2 per barrel ("/bbl") from 2019 levels to average $59/bbl for the
year. For 2021, the EIA expects WTI prices will rise further to an average of
$62/bbl. The EIA expects oil prices above $60/bbl to contribute to rising crude
oil production, as producers will be able to fund drilling programs through cash
flow and other funding sources, despite a somewhat more restrictive capital
market. Daily and monthly average crude oil prices could vary significantly from
annual average forecasts due to global economic developments and geopolitical
events in the coming months that could have the potential to push oil prices
higher or lower than forecast. Uncertainty remains regarding the duration of,
and members' adherence to, the current Organization of the Petroleum Exporting
Countries ("OPEC") production cuts, which could influence prices in either
direction.
We believe the recent stability of crude oil prices during 2019 and 2018 has
allowed for the continued build-out of related large-scale natural gas
infrastructure projects, particularly in the Permian and Delaware Basins. Our
total fleet horsepower has increased by approximately 86,000 horsepower as of
December 31, 2019 compared to December 31, 2018, while maintaining horsepower
utilization at approximately 94%.
We intend to prudently deploy capital for new compressor units in 2020. We have
already entered into commitments to purchase all of our large horsepower
compressor units for the first half of 2020, as the lead time to build these
units is approximately six months. Most of our 2020 purchases of large
horsepower compressor units are already committed to customers or under contract
with customers.
Factors Affecting the Comparability of our Operating Results
As described above, the USA Compression Predecessor has been deemed to be the
accounting acquirer of the Partnership in accordance with applicable business
combination accounting guidance, and, as a result, the historical financial
statements reflect the results of operations of the USA Compression Predecessor
for periods prior to the Transactions Date. Therefore, the Partnership's future
results of operations may not be comparable to the USA Compression Predecessor's
historical results of operations for the reasons described below.
The revenues generated by the Partnership consist of the revenues from
compression services as well as related ancillary revenues, including those
generated by the USA Compression Predecessor, subsequent to the Transactions
Date. The historical revenues included within the Partnership's financial
statements relating to periods prior to the Transactions Date are only comprised
of those of the USA Compression Predecessor.
Additionally, selling, general and administrative expenses will not be
comparable to the selling, general and administrative expenses previously
allocated to the USA Compression Predecessor by ETO. The Partnership's selling,
general and administrative expenses will also not be comparable to the
historical USA Compression Predecessor's selling, general and administrative
expenses because the Partnership's selling, general and administrative expenses
will include the expenses associated with being a publicly traded master limited
partnership, whereas the USA Compression Predecessor was operated as a component
of a larger company.
The Partnership incurs interest on its long-term debt and makes distributions to
its unitholders. The USA Compression Predecessor held no long-term debt and had
no outstanding publicly traded equity securities. As a result, the Partnership's
long-term debt and related charges will not be comparable to the USA Compression
Predecessor's historical long-term debt and related charges.

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During the year ended December 31, 2018, we recorded $4.2 million in transaction
expenses, $3.2 million in severance expenses and $6.8 million in unit-based
compensation expense, all of which related to the CDM Acquisition.
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


                                                     2019             2018

Change


Fleet horsepower (at period end) (1)              3,682,968         3,597,097           2.4  %

Total available horsepower (at period end) (2) 3,709,468 3,675,447

           0.9  %
Revenue generating horsepower (at period end)
(3)                                               3,310,024         3,262,470           1.5  %
Average revenue generating horsepower (4)         3,279,374         2,760,029          18.8  %
Average revenue per revenue generating
horsepower per month (5)                        $     16.65       $     16.09           3.5  %
Revenue generating compression units (at period
end)                                                  4,559             4,629          (1.5 )%
Average horsepower per revenue generating
compression unit (6)                                    720               687           4.8  %
Horsepower utilization (7):
At period end                                          93.7 %            94.0 %        (0.3 )%
Average for the period (8)                             94.1 %            91.4 %         3.0  %

________________________________

(1) Fleet horsepower is horsepower for compression units that have been delivered

to us (and excludes units on order). As of December 31, 2019, we had 56,500

horsepower on order for delivery during 2020.

(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 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 89.9% and 90.7% at December 31, 2019 and 2018,

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

89.8% and 87.5% for the years ended December 31, 2019 and 2018, respectively.




The 2.4% increase in fleet horsepower as of December 31, 2019 compared to
December 31, 2018 was attributable to compression units added to our fleet to
meet incremental demand by new and current customers for our compression
services. The 1.5% increase in revenue generating horsepower as of December 31,
2019 compared to December 31, 2018 was primarily due to organic growth in our
large horsepower fleet, while the 1.5% decrease in revenue generating
compression units was primarily due to returns of small horsepower compression
units from our customers, partially offset by the organic growth of large
horsepower compression units and a 4.8% increase in average horsepower per
revenue generating compression unit during the year ended December 31, 2019.
The 3.5% increase in average revenue per revenue generating horsepower per
month for the year ended December 31, 2019 compared to the year ended
December 31, 2018 was primarily due to contracts on new compression units as
well as selective price increases on the existing fleet.

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The 3.0% increase in average horsepower utilization and 2.6% increase in average
horsepower utilization based on revenue generating horsepower and fleet
horsepower during the year ended December 31, 2019 compared to the year ended
December 31, 2018 were primarily attributable to increased demand for our
services driven by increased U.S. production of crude oil and natural gas.
Financial Results of Operations
Year ended December 31, 2019 compared to the year ended December 31, 2018
The following table summarizes our results of operations for the periods
presented (dollars in thousands):
                                                   Year Ended December 31,         Percent
                                                     2019             2018          Change
Revenues:
Contract operations                             $    664,162      $  546,896          21.4  %
Parts and service                                     14,236          20,402         (30.2 )%
Related party                                         19,967          17,054          17.1  %
Total revenues                                       698,365         584,352          19.5  %
Costs and expenses:
Cost of operations, exclusive of depreciation
and amortization                                     227,303         214,724           5.9  %
Gross operating margin                               471,062         369,628          27.4  %
Other operating and administrative costs and
expenses:
Selling, general and administrative                   64,397          68,995          (6.7 )%
Depreciation and amortization                        231,447         213,692           8.3  %
Loss on disposition of assets                            940          12,964         (92.7 )%
Impairment of compression equipment                    5,894           8,666         (32.0 )%
Total other operating and administrative costs       302,678         304,317
and expenses                                                                          (0.5 )%
Operating income                                     168,384          65,311         157.8  %
Other income (expense):
Interest expense, net                               (127,146 )       (78,377 )        62.2  %
Other                                                     80              41          95.1  %
Total other expense                                 (127,066 )       (78,336 )        62.2  %
Net income (loss) before income tax expense           41,318         (13,025 )
(benefit)                                                                            417.2  %
Income tax expense (benefit)                           2,186          (2,474 )       188.4  %
Net income (loss)                               $     39,132      $  (10,551 )       470.9  %


Contract operations revenue.  The $117.3 million increase in contract operations
revenue for the year ended December 31, 2019 compared to the year ended
December 31, 2018 was primarily attributable to the first three months of 2018
including only the results of the USA Compression Predecessor prior to the
Transactions Date. Average revenue generating horsepower increased 18.8% for the
year ended December 31, 2019 compared to the year ended December 31, 2018
primarily due to the inclusion of the Partnership's historical assets subsequent
to the Transactions Date. Additionally, we experienced a year-to-year increase
in demand for our compression services driven by increased U.S. production of
crude oil and natural gas as average revenue per revenue generating horsepower
per month increased 3.5% to $16.65 for the year ended December 31, 2019 compared
to $16.09 for the year ended December 31, 2018.
Parts and service revenue.  The $6.2 million decrease in parts and service
revenue for the year ended December 31, 2019 compared to the year ended
December 31, 2018 was primarily attributable to a decrease 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.

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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 $2.9 million increase in related party revenue for the year ended
December 31, 2019 compared to the year ended December 31, 2018 was primarily
attributable to additional compression and related ancillary services demand
from such affiliates.
Cost of operations, exclusive of depreciation and amortization. The $12.6
million increase in cost of operations for the year ended December 31, 2019
compared to the year ended December 31, 2018 was driven by (1) a $21.1 million
increase in direct expenses, such as parts and fluids expenses, and (2) a $5.3
million increase in direct labor expenses, for which both increases were
primarily attributable to the first three months of 2018 including only the
results of the USA Compression Predecessor prior to the Transactions Date. These
increases were partially offset by (1) a $5.0 million decrease in ad valorem tax
expense, due primarily to prior year refunds received during the year ended
December 31, 2019, (2) a $3.9 million decrease in retail parts and service
expenses, which have a corresponding decrease in parts and service revenue, (3)
a $3.9 million decrease in outside maintenance services and (4) a $1.1 million
decrease in other indirect expenses.
Gross operating margin. The $101.4 million increase in gross operating margin
for the year ended December 31, 2019 compared to the year ended December 31,
2018 was primarily due to an increase in revenues, partially offset by an
increase in cost of operations, exclusive of depreciation and amortization.
These increases were primarily due to the addition of the Partnership's
historical assets after the Transactions Date and higher demand for our services
driven by increased U.S. production of crude oil and natural gas.
Selling, general and administrative expense.  The $4.6 million decrease in
selling, general and administrative expense for the year ended December 31, 2019
compared to the year ended December 31, 2018 was primarily attributable to (1) a
$5.9 million decrease in transaction expenses and severance expenses, (2) a $3.2
million decrease in other miscellaneous expenses, partially offset by (1) a $2.4
million increase in payroll and benefits expenses and (2) a $1.9 million
increase in professional fees expenses.
Transaction expenses and severance expenses were lower during the year ended
December 31, 2019 primarily due to the Transactions completed during the year
ended December 31, 2018. Other miscellaneous expenses decreased primarily due to
the expense allocation to the USA Compression Predecessor ending after the
Transactions Date. Payroll and benefits expenses and professional fees increased
due to the addition of the Partnership's historical assets after the
Transactions Date.
Depreciation and amortization expense.  The $17.8 million increase in
depreciation and amortization expense for the year ended December 31, 2019
compared to the year ended December 31, 2018 was primarily the result of the
addition of the Partnership's historical assets on the Transactions Date and
assets recently placed in service.
Loss on disposition of assets.  The $12.0 million decrease in net losses on
disposition of assets during the year ended December 31, 2019 compared to the
year ended December 31, 2018 was primarily attributable to disposals of various
property and equipment by the USA Compression Predecessor prior to the
Transactions Date during the year ended December 31, 2018.
Impairment of compression equipment.  The $5.9 million and $8.7 million
impairments of compression equipment during the years ended December 31, 2019
and 2018, respectively, were primarily the result of our evaluations of the
future deployment of our idle fleet under then-current market conditions. Our
evaluations determined that due to certain performance characteristics of the
impaired equipment, such as excessive maintenance costs and the inability of the
equipment to meet then-current emissions standards without excessive
retrofitting costs, this equipment was unlikely to be accepted by customers
under then-current market conditions.
As a result of our evaluations during the years ended December 31, 2019 and
2018, we determined to retire and re-utilize the key components of 33 and 103
compression units, respectively, with a total of approximately 11,000 and 33,000
horsepower, respectively, that had been previously used to provide compression
services in our business.
Interest expense, net.  The $48.8 million increase in interest expense, net for
the year ended December 31, 2019 compared to the year ended December 31, 2018
was primarily attributable to (1) higher overall debt balances as the USA
Compression Predecessor had no borrowings prior to the Transactions Date, (2)
interest expense incurred on $750.0 million of 6.875% senior notes issued in
March 2019, which were used to reduce borrowings under the Credit Agreement, and
(3) higher interest rates on borrowings under the Credit Agreement. These
increases were partially offset by the decrease in borrowings under the Credit
Agreement.
The weighted average interest rate applicable to borrowings under the Credit
Agreement was 4.84% for the year ended December 31, 2019 compared to 4.69% for
the period from the Transactions Date to December 31, 2018. Average outstanding

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borrowings under the Credit Agreement were $493.3 million for the year ended
December 31, 2019 compared to $984.7 million for the period from the
Transactions Date to December 31, 2018.
Income tax expense (benefit). During the years ended December 31, 2019 and 2018,
we recognized income tax expense of $2.2 million and an income tax benefit of
$2.5 million, respectively, primarily related to current and deferred taxes
associated with 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)                    2019            2018        Change
Gross operating margin                  $    471,062      $ 369,628      27.4  %
Gross operating margin percentage (2)           67.5 %         63.3 %     6.6  %
Adjusted EBITDA                         $    419,640      $ 320,475      30.9  %
Adjusted EBITDA percentage (2)                  60.1 %         54.8 %     9.7  %
DCF                                     $    221,868      $ 177,757      24.8  %
DCF Coverage Ratio (3)                         1.13x          1.25x      (9.6 )%
Cash Coverage Ratio (3)                        1.14x          1.26x      (9.5 )%

________________________________

(1) Gross operating 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) Gross operating margin percentage and Adjusted EBITDA percentage are

calculated as a percentage of revenue.

(3) Distributions for the year ended December 31, 2018 reflect only three

quarters of distributions as the USA Compression Predecessor did not pay

distributions prior to the Transactions Date. DCF, however, reflects a full

year of DCF. On a pro forma basis, both the DCF Coverage Ratio and Cash

Coverage Ratio for the year ended December 31, 2018 were 1.10x when using

comparable three quarters of DCF and three quarters of distributions.




Adjusted EBITDA. The $99.2 million, or 30.9%, increase in Adjusted EBITDA for
the year ended December 31, 2019 compared to the year ended December 31, 2018
was driven by the addition of the Partnership's historical assets after the
Transactions Date, which was the primary cause of a $101.4 million increase in
gross operating margin. This increase was partially offset by a $2.2 million
increase in selling, general and administrative expenses, excluding transaction
expenses, unit-based compensation expense and other non-recurring charges.
DCF. The $44.1 million, or 24.8%, increase in DCF during the year ended
December 31, 2019 compared to the year ended December 31, 2018 was driven by (1)
the addition of the Partnership's historical assets after the Transactions Date,
which was the primary cause of a $101.4 million increase in gross operating
margin, and (2) a $2.9 million decrease in maintenance capital expenditures.
These increases were partially offset by (1) a $46.2 million increase in cash
interest expense, net, (2) a $12.3 million increase in distributions on the
Preferred Units and (3) a $2.2 million increase in selling, general and
administrative expenses, excluding transaction expenses, unit-based compensation
expense and other non-recurring charges.
Coverage Ratios. The decreases in DCF Coverage Ratio and Cash Coverage Ratio for
the year ended December 31, 2019 compared to the year ended December 31, 2018
were attributable to the fact that distributions for year ended December 31,
2018 reflect only three quarters of distributions, as the USA Compression
Predecessor did not pay distributions prior to the Transactions Date, as well as
additional distributions in 2019 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.

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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 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 through 2020. 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.
To fund a portion of the CDM Acquisition, on March 23, 2018 the Partnership and
Finance Corp co-issued $725.0 million in aggregate principal amount of the
Senior Notes 2026 and, on the Transactions Date, the Partnership issued the
Preferred Units and Warrants for aggregate gross consideration of $500.0
million. The transaction fees associated with these issuances were financed with
borrowings under the Credit Agreement. Also on the Transactions Date, the
borrowing capacity under the Credit Agreement was increased from $1.1 billion to
$1.6 billion. In addition, on March 7, 2019, the Partnership and Finance Corp
co-issued $750.0 million aggregate principal amount of the Senior Notes 2027 and
used the net proceeds to reduce our outstanding borrowings under the Credit
Agreement.
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.
Cash Flows
The following table summarizes our sources and uses of cash for the years ended
December 31, 2019 and 2018 (in thousands):
                                                       Year Ended December

31,


                                                         2019

2018


Net cash provided by operating activities           $    300,580      $

226,340


Net cash used in investing activities                   (144,490 )

(779,663 ) Net cash provided by (used in) financing activities (156,179 ) 549,409




Net cash provided by operating activities.  The $74.2 million increase in net
cash provided by operating activities for the year ended December 31,
2019 compared to the year ended December 31, 2018 was primarily due
to a $58.7 million increase in net income, as adjusted for non-cash items, and
changes in other working capital.
Net cash used in investing activities.  The $635.2 million decrease in net cash
used in investing activities for the year ended December 31, 2019 compared to
the year ended December 31, 2018 was primarily due to (1) $1.2 billion of cash
paid, offset by $710.5 million of cash assumed, each as part of the CDM
Acquisition for the year ended December 31, 2018, (2) a $95.4 million decrease
in capital expenditures for purchases of new compression units, related
equipment and reconfiguration costs, (3) a $15.0 million increase in proceeds
from disposition of property and equipment and (4) a $3.8 million increase in
insurance proceeds received during the year ended December 31, 2019 for
compression units previously damaged.
Net cash provided by (used in) financing activities.  Net cash used in financing
activities for the year ended December 31, 2019 was $156.2 million compared to
net cash provided by financing activities of $549.4 million for the year ended
December 31, 2018. This change was primarily due to (1) $479.1 million of net
proceeds received during the year ended December 31, 2018 for the issuance of
Preferred Units and Warrants used to partially fund the CDM Acquisition, (2) an
increase of $51.9 million in cash distributions paid on common units, as the USA
Compression Predecessor did not pay distributions prior to the Transactions
Date, (3) an increase of $24.5 million of cash distributions paid on Preferred
Units as they were not outstanding prior to the Transactions Date, (4) a
decrease in net borrowings of $127.3 million for the year ended December 31,
2019, as additional borrowings for the year ended December 31, 2018 were made
primarily to pay fees and expenses related to the CDM Acquisition, and (5)
$28.5 million

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in intercompany contributions received by the USA Compression Predecessor for
the year ended December 31, 2018 from its former parent company.
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, 2019 and 2018 were $29.6 million and $32.5 million,
respectively. We currently plan to spend approximately $32.0 million in
maintenance capital expenditures during 2020, including parts consumed from
inventory.
Given our growth objectives and anticipated demand from our customers we
anticipate that we will continue to make expansion capital expenditures. Without
giving effect to any equipment we may acquire pursuant to any future
acquisitions, we currently have budgeted between $110.0 million and $120.0
million in expansion capital expenditures during 2020. Our expansion capital
expenditures for the years ended December 31, 2019 and 2018 were $170.3 million
and $208.7 million, respectively.
Revolving Credit Facility
As of December 31, 2019, we were in compliance with all of our covenants under
the Credit Agreement. As of December 31, 2019, we had outstanding borrowings
under the Credit Agreement of $402.7 million, $1.2 billion of borrowing base
availability and, subject to compliance with the applicable financial covenants,
available borrowing capacity of $484.4 million.
As of February 13, 2020, we had outstanding borrowings under the Credit
Agreement of $422.5 million. We expect to remain in compliance with our
covenants under the Credit Agreement throughout 2020. 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".
Senior Notes
On March 7, 2019, the Partnership and Finance Corp co-issued $750.0
million aggregate principal amount of senior notes due on September 1, 2027 (the
"Senior Notes 2027"). The Senior Notes 2027 accrue interest from March 7, 2019
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, with the first such
payment having occurred on September 1, 2019.
On December 18, 2019, the Partnership closed an exchange offer whereby holders
of the Senior Notes 2027 exchanged all of the Senior Notes 2027 for an
equivalent amount of senior notes ("Exchange Notes 2027") registered under the
Securities Act. The Exchange Notes 2027 are substantially identical to the
Senior Notes 2027, except that the Exchange Notes 2027 have been registered with
the SEC and do not contain the transfer restrictions, restrictive legends,
registration rights or additional interest provisions of the Senior Notes 2027.

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See Note 10 to our consolidated financial statements in Part II, Item 8
"Financial Statements and Supplementary Data" for information regarding the
Senior Notes.
Distribution Reinvestment Plan
During the years ended December 31, 2019 and 2018, distributions of $1.0 million
and $0.6 million, respectively, were reinvested under the DRIP resulting in the
issuance of 60,584 and 39,280 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, 2019 (in thousands):
                                                           Payments Due by

Period


                                               Less than 1                                          More than
Contractual Obligations           Total           year          1 - 3 years       3 - 5 years        5 years
Long-term debt (1)            $ 1,877,722     $         -     $           -     $     402,722     $ 1,475,000
Interest on long-term debt
obligations (2)                   807,487         123,253           246,507           208,274         229,453
Equipment and capital
purchases (3)                      49,267          49,267                 -                 -               -
Operating and finance lease
obligations (4)                    36,078           5,311             8,587             7,773          14,407
Total contractual cash
obligations                   $ 2,770,554     $   177,831     $     255,094

$ 618,769 $ 1,718,860

________________________________

(1) We assumed that the amount outstanding under the Credit Agreement at

December 31, 2019 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, 2019, and the effective interest

rate and unused commitment fee as of December 31, 2019 of 4.31% and 0.375%,

respectively, and interest payments on our $1.5 billion aggregate principal

amount of the Senior Notes.

(3) Represents commitments for new compression units that are being fabricated

and is a component of our overall projected expansion capital expenditures

during 2020 of $110.0 million to $120.0 million.

(4) 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 three 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, we
evaluate our estimates; however, actual results may differ from these estimates
under different assumptions or conditions. The accounting policies that

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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 at 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. If the growth assumptions embodied in the current year impairment
testing prove inaccurate, we could incur an impairment charge in the future.
As of December 31, 2019, the Partnership had $619.4 million of goodwill, of
which $366.0 million was determined as part of the purchase price allocation to
the Partnership's assets acquired by the USA Compression Predecessor.

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As of October 1, 2019 and 2018, 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 is 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 years ended December 31, 2019 and
2018.
One key assumption for the measurement of goodwill impairment is management's
estimate of future cash flows and EBITDA. These estimates are based on the
annual budget for the upcoming year and forecasted amounts for multiple
subsequent years. The annual budget process is typically completed near the
annual goodwill impairment testing date, and management uses the most recent
information for the annual impairment tests. The forecast is also subjected to a
comprehensive update annually in conjunction with the annual budget process and
is revised periodically to reflect new information and/or revised expectations.
As discussed above, estimates of fair value can be affected by a variety of
external and internal factors. Volatility in crude oil prices can cause
disruptions in global energy industries and markets. Potential events or
circumstances that could reasonably be expected to negatively affect the key
assumptions we used in estimating the fair value of our reporting unit 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.
We continue to monitor the $619.4 million balance of goodwill and if the
estimated fair value of our reporting unit declines due to any of these or other
factors, we may be required to record future goodwill impairment charges.
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, 2019 and 2018, we evaluated the future
deployment of our idle fleet under then-current market conditions and
determined to retire and re-utilize key components of 33 and 103 compressor
units, respectively, or approximately 11,000 and 33,000 horsepower,
respectively, that were previously used to provide services in our business. As
a result, we recorded $5.9 million and $8.7 million in impairment of compression
equipment for the years ended December 31, 2019 and 2018, respectively. The
primary causes for this impairment 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 then-current quoting criteria without excessive retrofitting costs. These
compression units were written down to their respective estimated
salvage values, if any.
Allowances and Reserves
We maintain an allowance for doubtful accounts based on specific customer
collection issues and historical experience. The determination of the allowance
for doubtful accounts requires us to make estimates and judgments regarding our
customers' ability

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to pay amounts due. On an ongoing basis, we conduct an evaluation of the
financial strength of our customers based on payment history, the overall
business climate in which our customers operate and specific identification of
customer bad debt 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
For discussion on the adoption of Accounting Standards Update 2016-02 Leases and
other specific recent accounting pronouncements affecting us, please see Note 2
and Note 18, respectively, to our consolidated financial statements in Part II,
Item 8 "Financial Statements and Supplementary Data".
ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk


Commodity Price Risk
Market risk is the risk of loss arising from adverse changes in market rates and
prices. We do not take title to any natural gas or crude oil in connection with
our services and, accordingly, have no direct exposure to fluctuating commodity
prices. However, the demand for our compression services depends upon the
continued demand for, and production of, natural gas and crude oil. Sustained
low natural gas or crude oil prices over the long term could result in a decline
in the production of natural gas or crude oil, which could result in reduced
demand for our compression services. We do not intend to hedge our indirect
exposure to fluctuating commodity prices. A one percent decrease in average
revenue generating horsepower during the year ended December 31, 2019 would have
resulted in a decrease of approximately $6.6 million and $4.4 million in our
revenue and gross operating margin, respectively. Gross operating margin is a
non-GAAP financial measure. For a reconciliation of gross operating margin to
net income (loss), its most directly comparable financial measure, calculated
and presented in accordance with GAAP, please read Part II, Item 6 "Selected
Financial Data - Non-GAAP Financial Measures". Please also read Part I, Item 1A
"Risk Factors - Risks Related to Our Business - A long-term reduction in the
demand for, or production of, natural gas or crude oil in the locations where we
operate could adversely affect the demand for our services or the prices we
charge for our services, which could result in a decrease in our revenues and
cash available for distribution to unitholders".
Interest Rate Risk
We are exposed to market risk due to variable interest rates under our Credit
Agreement.
As of December 31, 2019, we had approximately $402.7 million of variable-rate
outstanding indebtedness at a weighted-average interest rate of 4.31%. A one
percent increase or decrease in the effective interest rate on our variable-rate
outstanding debt as of December 31, 2019 would result in an annual increase or
decrease in our interest expense of approximately $4.0 million.
For further information regarding our exposure to interest rate fluctuations on
our debt obligations, see Note 10 to our consolidated financial statements in
Part II, Item 8 "Financial Statements and Supplementary Data". Although we do
not currently hedge our variable rate debt, we may, in the future, hedge all or
a portion of such debt.
Credit Risk
Our credit exposure generally relates to receivables for services provided. If
any significant customer of ours should have credit or financial problems
resulting in a delay or failure to repay the amount it owes us, it could have a
material adverse effect on our business, financial condition, results of
operations or cash flows.
ITEM 8. Financial Statements and Supplementary Data


The financial statements and supplementary information specified by this Item
are presented in Part IV, Item 15 "Exhibits and Financial Statement Schedules".
ITEM 9.      Changes in and Disagreements With Accountants on Accounting and
             Financial Disclosure


None.

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