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May 5, 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

Filed   February 11, 2016

Form 8-K

Filed   February 10, 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 April 21, 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”) and (ii) the Partnership’s Current Report on Form 8-K, File No. 001-35779,  filed with the Commission on February 10, 2016.

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.              We note your statement that there has been a slowdown of new drilling activity in certain operating areas, as well as slowing or flattening of production growth in other areas. Given that the decline in oil and gas prices has had differing impacts on different shale plays, please respond to the following:

·                  Please tell us whether your assets are spread evenly across the shale plays in which you operate or whether they are concentrated in one or a few shale plays.

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·                  Please consider disclosing a map similar to that provided in your initial public offering or a table indicating your horsepower in different shales or geographic regions to clarify to your investors any concentration of your assets.

·                  Also tell us how you considered providing more detailed disclosure about the differing impact of continued low commodity prices on different shale plays as context for understanding your results of operations. For example, we note that exploration and production companies operating in shale plays in Texas have experienced greater declines in production and more bankruptcies than companies operating in other geographic regions.

RESPONSE:         We acknowledge the Staff’s comment.  As noted on page 45 of our 2015 Form 10-K, 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.  Over time, our geographic presence and relative diversification has varied among different operating basins, as we partner with customers who experience continually-changing economics in these various areas, due not only to changes in commodity prices, but also varying acquisition costs and operating costs, sometimes within the same basin or play. While our assets are not spread evenly across these shale plays, we believe our assets are diversified across these shale plays and we are not exposed to material concentration risk in any one play.

As noted on page 3 of our 2015 Form 10-K, our fleet consists of flexible compression units that are capable of being rapidly deployed and designed to operate in multiple compression stages.  This means that our compression units are designed for use in the varied operating conditions found in different plays. This flexibility provides us the ability (i) to expand into different geographic areas without incurring material expenditures, substantially reducing the concentration risk of our assets relative to exploration and production companies and gathering and processing and pipeline-based midstream companies, who cannot move their asset base as easily or cost-effectively, and (ii) to more easily take advantage of overall growth in natural gas production in the United States (as such growth is predicted by the U.S. Energy Information Administration). In fact, this flexibility of our asset design is a key strategic advantage that we believe differentiates us from certain of our peers. Due to the flexibility of the compression units in our fleet, our belief that our asset base is materially diversified across the shale plays in which we currently operate and the variety of producer economics within shale plays, we respectfully submit to the Staff that disclosure of our horsepower by shale or region would not provide meaningful information to investors, in that the continued demand for our services within a play may vary more by the economics of our customers than the relative general economics of one or more shale plays.  To the extent that we determine in the future that we are subject to a material concentration risk due to a specific customer or shale play, we hereby undertake to provide additional disclosure regarding such specific risk in future filings with the Commission.

Securities and Exchange Commission

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We respectfully submit to the Staff that more detailed disclosure about the differing impact of continued low commodity prices on different shale plays will not provide meaningful information to investors, due to the variety of producer economics within plays, which would be unduly burdensome for us to obtain since production information (and the underlying production economics) are the purview of our customers rather than us.  As noted above, we believe our assets are diversified across multiple shale plays and are also flexible enough to be redeployed in multiple operating conditions as needed.  In addition, low commodity prices tend to have a greater impact on the drilling and completion of new wells than they do on production from existing wells, and our business is driven predominantly by natural gas production.  As such, we believe that while low commodity prices could lead to less, or more delayed, incremental demand for our compression services than in the recent past, existing production will continue to require the compression services we offer.  Further, while the demand for our compression services is driven predominantly by natural gas production, there are a myriad of additional factors (such as reservoir pressure and flow rates and pipeline characteristics), known by producers but not necessarily by us, that impact the need for compression and that make quantification of any change in natural gas production from any given shale play difficult to accurately determine, and therefore, potentially confusing and not meaningful to an investor.  Finally, the “fixed-fee” nature of our contracts attenuates revenue losses from decreased production.  As such, we respectfully submit to the Staff that the disclosure we have provided on pages 45-46 of our 2015 Form 10-K under the heading “General Trends and Outlook” complies with Item 303(a) of Regulation S-K in that it prominently discloses the material risks of our exposure to the uncertainty associated with commodity prices, including the impact of low commodity prices.  To the extent that the material risks of our exposure to the uncertainty associated with commodity prices changes from, or we are able to provide more definitive quantification of the material risk than, the disclosure we have provided on pages 45-46 of our 2015 Form 10-K, we will update such disclosure accordingly in future filings with the Commission on Form 10-Q or Form 10-K.

In addition, as we reference above, we respectfully submit to the Staff that providing additional detailed disclosure would be unduly burdensome on the Partnership.  While we believe that the key drivers of production across shale plays are centered upon producers’ mid- or long-term expectations regarding commodity prices, different shale plays, and even zones within each shale play, have different factors driving the potential economics of the area, including reservoir characteristics and type curves, service costs, financing costs, etc.  Given the lack of information we have from our customers regarding such factors, it would be very difficult, if not impossible, for us to gather the economic information needed to provide more detailed disclosure than we currently have provided in our 2015 Form 10-K.

2.              We note your statement that the steep decline in commodity prices has caused many of your customers to reconsider near-term capital budgets as well as to reexamine and optimize their compression needs, which impacts the associated demand for compression. We also note from disclosures elsewhere in the filing that while you initially enter into take-or-pay contracts with your customers, once those contracts expire you may provide services on a month-to-month basis; and at December 31, 2015, approximately 39% of your compression services on a horsepower basis and 43% of your

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annual revenues were being provided on a month-to-month basis. We have the following comments:

·             Please tell us how you monitor the credit quality of your producer customers and how you considered whether the collectability of your accounts receivable has been impacted by the decline in commodity prices or may be impacted in the near-term.

·             Please tell us whether you have renegotiated the fees on any long-term contracts prior to their expiration or whether you are currently in the process of renegotiating any such contracts prior to their expiration. We note your reference to making rate concessions on certain gas lift contracts, and it is unclear whether you have made similar concessions on any compression services contracts. If so, please tell us in detail how you considered contract renegotiations that have occurred or are likely to occur in the near future in explaining trends and uncertainties in your results of operations.

·             Please tell us in more detail how rates are determined for those contracts where services are provided on a month-to-month basis. Also tell us whether rates increased or decreased for this type of contract during 2015. Based on this information, tell us how you considered separately discussing the impact of month-to-month contracts on your revenue and profitability.

·             Please also tell us, and consider disclosing in future filings, the horsepower associated with contracts that expire within one year and your expectations regarding the number of month-to-month contracts and the fees from such contracts.

RESPONSE:         We acknowledge the Staff’s comment.  We actively monitor our customers’ credit quality and have continued to do so during the recent downturn in commodity prices.  We take into consideration multiple factors in monitoring our customers, including, but not limited to, (i) tracking the payment history of our customers, (ii) actively communicating with each of our customers, (iii) monitoring various credit reporting information services, and (iv) monitoring bankruptcy filings in our industry.  In addition, we monitor publicly-available information about each of our customers that may highlight potential financial distress, such as debt levels (including large credit facility borrowings), the failure to make interest payments when due, or entering into forbearance agreements with lenders.  If, as a result of these monitoring activities, we determine the collectability of accounts receivable with a particular customer may be negatively impacted, we may elect to alter our normal collection processes with that particular customer to increase the likelihood of being paid in full.  We do not specifically consider commodity prices when evaluating collectability of accounts receivable from our customers, as we are not able to accurately evaluate our customers’ specific economic position and circumstances regarding commodity price movements.  However, in response to the current commodity price environment, management has been more focused on the possibility of a decline in the collectability of accounts receivable, as well as the implications of changes in payment history and communication patterns of

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customers, and we have made additional judgments as to the adequacy of our allowance for bad debts.  We noted such in the Critical Accounting Policies and Estimates of our 2015 Form 10-K (bold, underline text was added in the 2015 10-K):

“We maintain an allowance for bad debts 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 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. The allowance for doubtful accounts was $2.1 million, $0.4 million and $0.2 million as of December 31, 2015, 2014 and 2013, respectively.”

The increase in allowance for doubtful accounts from $0.4 million as of December 31, 2014 to $2.1 million as of December 31, 2015 was largely related to an increase in the aging of our accounts receivable, a lack of responsiveness of one customer, and the bankruptcy of another customer.  We collected the overdue receivable from the unresponsive customer in the three months ended March 31, 2016 and now expect to collect a substantial majority of the amount reflected in the allowance for doubtful accounts associated with the bankruptcy in the three months ending June 30, 2016.

Substantially all of our contracts are term-based contracts that have significant take-or-pay characteristics in that they do not provide customers the unilateral right to renegotiate pricing, or terminate service, during the primary term. While we have renegotiated the fees on a very small number (by horsepower) of compression services contracts, in various applications, we typically do not do so during the primary term.  As we note on page 45 of our 2015 Form 10-K, we have generally experienced stability in rates and higher sustained utilization rates relative to other businesses more tied to drilling activity and wellhead economics.  The contract renegotiations we have experienced, and expect to experience in the future, have not had, and are not reasonably likely to have, a material effect on the Partnership’s financial condition or results of operations.  Based on this, we believe that we have adequately disclosed the impact of contract renegotiations in our 2015 Form 10-K in compliance with Item 303(a) of Regulation S-K, as we note on page 45 that we have experienced and expect to continue experiencing pressure on service rates.  To the extent that management believes renegotiations of service rates on any contracts will have a material effect on the Partnership’s financial condition or results of operations, we hereby undertake to provide additional disclosure regarding the impact of such renegotiations to investors in future filings with the Commission.

In regard to the contracts with our customers that have entered the extended, “month-to-month,” term of the contract, the service rates for these contracts, in the vast majority of cases, is based off of and continues at the same level as the service rates provided in the primary term of the contract.  As such, we believe that providing any additional information regarding service rate pricing would not be meaning