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June 16, 2016

Ms. Jennifer Thompson

Accounting Branch Chief

United States Securities and Exchange Commission

Division of Corporation Finance

100 F Street, N.E.

Washington, D.C.  20549-3561

Re:                       USA Compression Partners, LP

Form 10-K for the Fiscal Year Ended December 31, 2015

Response dated May 5, 2016

Form 8-K

Filed May 5, 2016

Form 10-Q for the Fiscal Quarter Ended March 31, 2016

Filed May 5, 2016

File No. 001-35779

Ladies and Gentlemen:

Set forth below are the responses of USA Compression Partners, LP (the “Partnership,” “we,” “us” or “our”), to comments received from the staff of the Division of Corporation Finance (the “Staff”) of the Securities and Exchange Commission (the “Commission”) by letter dated May 18, 2016, with respect to (i) the Partnership’s Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2015, File No. 001-35779, filed with the Commission on February 11, 2016 (our “2015 Form 10-K”), (ii) the Partnership’s Current Report on Form 8-K, File No. 001-35779, filed with the Commission on May 5, 2016 and (iii) the Partnership’s Quarterly Report for the Fiscal Quarter Ended March 31, 2016, File No. 001-35779, filed with the Commission on May 5, 2016 (our “Form 10-Q”).

For your convenience, each response is prefaced by the exact text of the Staff’s corresponding comment in bold, italicized text.

Form 10-K for the Fiscal Year Ended December 31, 2015

Management’s Discussion and Analysis of Financial Condition and Results of Operations

General Trends and Outlook, page 45

1.        Your response to comment 1 indicates that your compression fleet can be quickly and cost-effectively modified and moved between shale plays and disclosure of your horsepower by shale or region would not provide meaningful information to your investors. To assist us in better understanding your response, please tell us how

Securities and Exchange Commission

June 16, 2016

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frequently you move your equipment between shale plays. Please also tell us the average time and costs associated with redesigning and deploying such equipment during the year ended December 31, 2015, or during the most recent year in which you moved equipment between shale plays.

RESPONSE:                            We acknowledge the Staff’s comment.  As noted in our prior response, our equipment is designed to be quickly and cost-effectively modified and moved between shale plays.  During the year ended December 31, 2015, we moved 485 units to new locations, excluding units that moved within the same shale play or basin.  We typically store our equipment at our two primary equipment yards, located in Pennsylvania for the northeast shale plays and in Oklahoma for the other shale plays in which we operate.  During the year ended December 31, 2015, we did not move any units between our Oklahoma and Pennsylvania yards, excluding new units moving from our fabricators to the Pennsylvania yard to begin initial service, and we have very rarely in our operating history moved our equipment between our primary yards.  The rarity of moves between Oklahoma and Pennsylvania is primarily due to: (i) adequate inventory in each yard to meet customers’ demands in the respective operative region and (ii) continued compression needs from existing natural gas production, even in a reduced commodity price environment.

Whether modifications are necessary for a specific compression unit that is moved between locations depends on the difference in operating conditions between locations and not whether the moves are between shale plays.  In most cases, when a unit has been moved within the same region, even if between shale plays, no significant modifications have been required to operate the unit in the new location because operating conditions have been similar enough between the locations.  When, instead, modifications are necessary to allow the compression unit to operate in different operating conditions, the gross cost to do so is typically a maximum of $50,000 to $70,000 per compression unit, which is less than 6% of our most common compression unit’s initial cost, and the modification typically takes approximately 3-5 days when parts are readily available from our inventory.  During the year ended December 31, 2015, we incurred this level of modification costs on only 31 of the 485 compression units moved to a new location.

In regards to transportation cost, our customers contractually incur the cost associated with moving the unit between our equipment yard and the location where they require compression, but we would typically pay to move units between our Oklahoma and Pennsylvania yards.  Although we have not moved any units between our Oklahoma and Pennsylvania yards during the year ended December 31, 2015, we estimate the cost we would incur to do so would be approximately $85,000 and the relocation would take approximately 4-5 days.  The typical relocation time between our customer’s locations and our nearest primary yard is approximately 2-3 days (not including time connecting the unit to the existing infrastructure at the new location, which can vary depending on multiple factors, but on average can take an additional 4 days).

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2.        Your response to the first bullet point of comment 2 describes various ways in which you monitor your customers’ credit quality. Please consider revising your critical accounting policy addressing your allowance for doubtful accounts to explain in more detail the estimates and judgments you make about your customers’ ability to pay and any trends you have observed in your customers’ credit quality rather than simply stating that you make estimates and judgments and that you evaluate your customers’ financial strength. Additionally, since it appears from your response that you monitor your customers’ credit ratings, please tell us whether any of your largest customers have credit ratings below investment grade, and tell us how you considered disclosing this information as part of providing investors with insight into the potential risks to and variability of your earnings and cash flows.

RESPONSE:                            We acknowledge the Staff’s comment. In response to the Staff’s comment, we hereby undertake to modify our critical accounting policy disclosure in future Form 10-K filings and our trade accounts receivable footnote in future Form 10-Q filings with the Commission in order to provide additional details regarding the factors considered when making estimates and judgments regarding our allowance for doubtful accounts as well as the trends we are experiencing in customers credit quality.  As an example of this additional disclosure, please see the bold, underlined text below to be added to our trade accounts receivable footnote in future filings:

“Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts, which was $1.3 million and $2.1 million at March 31, 2016 and December 31, 2015, respectively, is the Partnership’s best estimate of the amount of probable credit losses included in the Partnership’s existing accounts receivable. The Partnership determines the allowance based upon historical write-off experience and specific customer circumstances. The determination of the allowance for doubtful accounts requires us to make estimates and judgments regarding our customers’ ability 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 review of various publicly-available materials regarding our customers’ industries, including specifics regarding the solvency of various companies in the industry.  Although the Partnership has not yet experienced an increase in actual write-offs, the aforementioned factors reviewed by the Partnership led to an increase in the allowance for doubtful accounts during the twelve months ended December 31, 2015.   During the three months ended March 31, 2016, the Partnership decreased its allowance for doubtful accounts by $0.8 million.  This was due in part to collections on accounts that had previously been reserved due to bankruptcy or significantly delinquent balances. The Partnership does not have any off-balance-sheet credit exposure related to its customers. Although the overall energy industry continues to be volatile, it is not certain that the factors leading to an increase in the allowance for doubtful accounts during 2015 will continue in 2016.”

Securities and Exchange Commission

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As noted by the Staff, we monitor our customers’ credit ratings as only a part of our determination of the allowance for doubtful accounts.  We respectfully note that a change in a customer’s credit rating will not directly impact the allowance for doubtful accounts.  Rather, the rating is one of multiple factors considered in determining the adequacy of the allowance for doubtful accounts.  We have, and historically have had, customers with a credit rating below investment grade.  Our top ten customers for the year ended December 31, 2015 represented 45% of our revenue.  Two of these ten customers had a credit rating below investment grade, one customer did not have a credit rating and one customer consisting of multiple entities considered a “single customer” under Item 101(c)(1)(vii) of Regulation S-K had 89% of its revenue attributable to entities with no credit rating and 11% of its revenue attributable to an entity with a rating below investment grade.  We respectfully note that we have provided the following disclosure under the risk factor “The deterioration of the financial condition of our customers could adversely affect our business” on page 16 of our 2015 Form 10-K:

“…In addition, in the course of our business we hold accounts receivable from our customers.  In the event that any such customer was to enter into bankruptcy, we could lose all or a portion of such outstanding accounts receivable associated with that customer.  Further, if a customer was to enter into bankruptcy, it could also result in the cancellation of all or a portion of our service contracts with such customer at significant expense to us.”

We respectfully believe that additional disclosure of the potential risk noted by the Staff in addition to what we have provided in the above risk factor would place undue prominence on the risk when balanced against the materiality thereof, and therefore the meaningfulness, of the information.  Our belief is based on our historical experience that our earnings and cash flows have yet to be materially impacted by any inability to collect our receivables on a timely basis as well as the fact we take into consideration our customers’ credit ratings in determining our allowance for doubtful accounts, which helps quantify the credit risk associated with our customers.  We will continue to monitor our customers’ ability to pay closely and hereby undertake to disclose additional information, when material, regarding such ability as it relates to the impact on our earnings and cash flows.

3.        We note your response to the second bullet point of comment 2. Given your risk factor disclosures about the possible impact of contract renegotiations, we believe you should clearly disclose in future filings, if true, that these negotiations did not have a material impact on your results of operations. We believe clarifying the impact of these contract negotiations provides important information to your investors.

RESPONSE:                            We acknowledge the Staff’s comment.  In response to the Staff’s comment, we hereby undertake to provide the following bold, underlined text in future filings with the commission:

“Contract operations revenue.  During 2015, we experienced an increase in demand for our compression services driven by an increase in overall natural gas production in the U.S., resulting in a 17.3% increase in average revenue generating horsepower and a $46.5 million increase in our contract operations revenue.  Average revenue per revenue generating horsepower per month increased from $15.57 for the year ended December 31, 2014 to $15.90 for the year ended

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December 31, 2015, an increase of 2.1%, attributable, in part, to growth in the small horsepower fleet, which earns higher revenue per horsepower, in addition to improved pricing in the large horsepower fleet.  Because the demand for our services is driven primarily by production of natural gas, we focus our activities in areas of attractive growth, which are generally found in certain shale and unconventional resource plays, as discussed above under the heading “Overview.”  Our contract operations revenue was not materially impacted by any renegotiations of our contracts during the period with our customers.”

4.        We note your response to the third bullet point of comment 2. Please tell us how the service rates for your month-to-month contracts differed from the service rates for contracts in their primary term during 2015, including whether they were generally above or below the rates for contracts in their primary term. In future filings, please disclose this information for the periods presented, including if applicable making an affirmative statement that rates for month-to-month contracts did not significantly differ from rates for contracts in their primary term. Given that a significant percentage of your contracts are operating on a month-to-month basis and the increased ability of these customers to renegotiate pricing or terminate service as compared to customers with contracts in their primary term, we believe that explaining in more detail the impact of month-to-month contracts on your results and any factors that cause these contracts to have significantly different impacts on your consolidated results and cash flows as compared to contracts in their primary term provides important information to your investors.

RESPONSE:                            We acknowledge the Staff’s comment.  As we previously noted, the service rates for our contracts in the extended “month-to-month” term are simply an extension of the same service rates from the primary term of the contract in a vast majority of cases.  In the aggregate, our service rates for our contracts in the extended “month-to-month” term did not materially differ from our contracts in the primary term.  For the fiscal year ended December 31, 2015, the average service rate for our contracts in the extended “month-to-month” term was $16.17/hp and our average service rate for our contracts in the primary term was $15.74/hp.  As noted on pages 47 and 49 of our 2015 Form 10-K, the average service rate for all of our contracts was $15.90/hp.  We do not believe that the difference in service rates from our contracts in primary term compared to the extended term will result in any material impact on our consolidated results and cash flows separate from the average service rate for all contracts already disclosed.  In response to the Staff’s comment, we hereby undertake to add the following bold, underlined text in future filings with the Commission:

“Contract operations revenue.  During 2015, we experienced an increase in demand for our compression services driven by an increase in overall natural gas production in the U.S.,