UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2012

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 001-35779

USA Compression Partners, LP

(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization)

75-2771546
(I.R.S. Employer
Identification No.)

100 Congress Avenue, Suite 450
Austin, TX
(Address of principal executive offices)

78701
(Zip Code)

(512) 473-2662

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class		Name of each exchange on which registered
Common Units representing Limited Partner Interests		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:
None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes o No x*

*We completed our initial public offering on January 18, 2013 and, accordingly, have not been subject to the reporting requirements under Section 13 or 15(d) of the Securities Exchange Act of 1934.

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o		Accelerated filer o

Non-accelerated filer x		Smaller reporting company o
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

As of June 30, 2012, the last business day of the registrant’s most recently completed second fiscal quarter, the registrant’s equity was not listed on any domestic exchange or over-the-counter market. The registrant’s common units began trading on the New York Stock Exchange on January 15, 2013. The aggregate market value of common units held by non-affiliates of the registrant (treating directors and executive officers of the registrant’s general partner and holders known to the registrant to own 5% or more of the common units outstanding, for this purpose, as if they were affiliates of the registrant) as of March 22, 2013 was $210,768,000. This calculation does not reflect a determination that such persons are affiliates for any other purpose.

As of March 22, 2013, there were 15,048,588 common units and 14,048,588 subordinated units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: NONE

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PART I

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

This report contains “forward-looking statements.” All statements other than statements of historical fact contained in this report are forward-looking statements, including, without limitation, statements regarding our plans, strategies, prospects and expectations concerning our business, results of operations and financial condition. You can identify many of these statements by looking for words such as “believe,” “expect,” “intend,” “project,” “anticipate,” “estimate,” “continue” or similar words or the negative thereof.

Known material factors that could cause our actual results to differ from those in these forward-looking statements are described below, in Part I, Item 1A (“Risk Factors”) and Part II, Item 7 (“Management’s Discussion and Analysis of Financial Condition and Results of Operations”) of this report. Important factors that could cause our actual results to differ materially from the expectations reflected in these forward-looking statements include, among other things:

· changes in general economic conditions;

· competitive conditions in our industry;

· changes in the long-term supply of and demand for natural gas;

· actions taken by our customers, competitors and third party operators;

· changes in the availability and cost of capital;

· operating hazards, natural disasters, weather related delays, casualty losses and other matters beyond our control;

· the effects of existing and future laws and governmental regulations; and

· the effects of future litigation.

All forward-looking statements included in this report are based on information available to us on the date of this report. Except as required by law, we undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the foregoing cautionary statements.

ITEM 1. Business

References in this report to “USA Compression,” “we,” “our,” “us,” “the Partnership” or like terms refer to USA Compression Partners, LP and its wholly owned subsidiaries, including USA Compression Partners, LLC (“USAC Operating”). References to “USA Compression Holdings” refer to USA Compression Holdings, LLC, the owner of USA Compression GP, LLC, our general partner. References to “Riverstone” refer to Riverstone/Carlyle Global Energy and Power Fund IV, L.P., and affiliated entities, including Riverstone Holdings LLC. References in this report to the “Predecessor” refer to USA Compression Partners, LP and its wholly owned subsidiaries for periods prior to December 31, 2010, which is a date of convenience relating to the date we were acquired by USA Compression Holdings. References in this report to the “Successor” refer to USA Compression Partners, LP and its wholly owned subsidiaries for periods from December 31, 2010 forward.

Overview

We are a growth oriented Delaware limited partnership and, based on management’s significant experience in the industry, we believe that we are one of the largest independent providers of compression services in the U.S. in terms of total compression unit horsepower. We have been providing compression services since 1998. As of December 31, 2012, we had 919,121 horsepower in our fleet and 87,975 horsepower on order for delivery which is expected to be delivered primarily in the first half of 2013. We employ a customer focused business philosophy in partnering with our diverse customer base, which is comprised of producers, processors, gatherers and transporters of natural gas. Natural gas compression, a mechanical process whereby natural gas is compressed to a

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smaller volume, resulting in higher pressure, is an essential part of the production and transportation of natural gas. As part of our services, we engineer, design, operate, service and repair our compression units and maintain related support inventory and equipment. The compression units in our modern fleet are designed to be easily adaptable to fit our customers’ dynamic compression requirements. By focusing on the needs of our customers and by providing them with reliable and flexible compression services, we are able to develop long-term relationships, which lead to more stable cash flows for our unitholders. From 2003 through 2012, our average horsepower utilization was over 90%.

We focus primarily on large horsepower infrastructure applications. As of December 31, 2012, we estimate that approximately 90% of our revenue generating horsepower was deployed in large volume gathering systems, processing facilities and transportation applications. We operate a modern fleet of compression units, with an average age of approximately five years. Our standard new-build compression unit is generally configured for multiple compression stages allowing us to operate our units across a broad range of operating conditions. This flexibility allows us to enter into longer-term contracts and reduces the redeployment risk of our horsepower in the field. Our modern and standardized fleet, decentralized field level operating structure and technical proficiency in predictive and preventive maintenance and overhaul operations have enabled us to achieve average service run times consistently above the levels required by our customers.

We generally provide our compression services to our customers under long-term, fixed-fee contracts, with initial contract terms of up to five years. We typically continue to provide compression services to our customers beyond their initial contract terms, either through contract renewals or on a month-to-month basis. Our customers are typically required to pay our monthly fee even during periods of limited or disrupted natural gas flows, which enhances the stability and predictability of our cash flows. We are not directly exposed to natural gas price risk because we do not take title to the natural gas we compress and because the natural gas used as fuel by our compression units is supplied by our customers without cost to us.

We provide compression services in a number of shale plays, including the Fayetteville, Marcellus, Woodford, Barnett, Eagle Ford and Haynesville shales. We believe compression services for shale production will increase in the future. According to the Annual Energy Outlook 2013 Early Release prepared by the EIA, natural gas production from shale formations will increase from 34% of total U.S. natural gas production in 2011 to 50% of total U.S. natural gas production in 2040. Not only are the production and transportation volumes in these and other shale plays increasing, but the geological and reservoir characteristics of these shales are also particularly attractive for compression services. The changes in production volume and pressure of shale plays over time result in a wider range of compression requirements than in conventional basins. We believe we are well-positioned to meet these changing operating conditions as a result of the flexibility of our compression units. While our business focus is largely compression services serving shale plays, we also provide compression services in more mature conventional basins. These conventional basins require increasing amounts of compression as they age and pressures decline, which we believe will provide an additional source of stable and growing cash flows for our unitholders.

Business Strategies

Our principal business objective is to increase the quarterly cash distributions that we pay to our unitholders over time while ensuring the ongoing stability and growth of our business. We expect to achieve this objective by executing on the following strategies:

· Capitalize on the increased need for natural gas compression in conventional and unconventional plays. We expect additional demand for compression services to result from the continuing shift of natural gas production to domestic shale plays as well as the declining production pressures of aging conventional basins. Our fleet of modern, flexible compression units, which are capable of being rapidly deployed and redeployed and many of which are designed to operate in multiple compression stages, will enable us to capitalize on opportunities both in these emerging shale plays as well as conventional fields.

· Continue to execute on attractive organic growth opportunities. Between 2003 and 2012, we grew the horsepower in our fleet of compression units and our compression revenues at a compound annual growth rate of 24%, primarily through organic growth. We believe organic growth opportunities will continue to be our most attractive source of near-term growth. We seek to achieve continued organic growth by (i) increasing our business with existing customers, (ii) obtaining new customers in our existing areas of operations and (iii) expanding our operations into new geographic areas.

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The following table provides a summary of our compression units by horsepower as of December 31, 2012 (including additional new compression unit horsepower on order for delivery between January 2013 and August 2013):

Unit Horsepower	Fleet Horsepower	Horsepower on Order (1)	Total Horsepower (2)	Percentage of Total Horsepower
<500	143,396	3,200	146,596	14.5	%
>500 <1,000	115,900	2,760	118,660	11.8	%
>1,000	659,825	82,015	741,840	73.7	%
Total	919,121	87,975	1,007,096	100.0	%

(1) As of March 22, 2013, 19,280 horsepower had been delivered and 6,900 horsepower is expected to be delivered in the remainder of March 2013, and 61,795 horsepower between April 2013 and August 2013.

(2) Comprised of 1,242 compression units, including 69 new compression units on order.

The following table sets forth certain information regarding our compression fleet as of the dates and for the periods indicated:

	Successor								Predecessor
	Year Ended December 31,				Percent Change				Year Ended December 31,				Percent Change
Operating Data (unaudited):	2012		2011		2012		2011		2010		2009		2010
Fleet horsepower(1)	919,121		722,201		27.3	%	18.4	%	609,730		582,530		4.7	%
Total available horsepower(2)	935,681		809,418		15.6	%	32.2	%	612,410		582,530		5.1	%
Revenue generating horsepower(3)	794,324		649,285		22.3	%	21.7	%	533,692		502,177		6.3	%
Average revenue generating horsepower(4)	749,821		570,900		31.3	%	10.5	%	516,703		489,243		5.6	%
Revenue generating compression units	978		888		10.1	%	11.7	%	795		749		6.1	%
Average horsepower per revenue generating compression unit(5)	791		692		14.3	%	3.7	%	667		655		1.8	%
Horsepower utilization(6):
At period end	92.8	%	95.7	%	(3.0	)%	4.2	%	91.8	%	92.0	%	(0.2	)%
Average for the period(7)	94.5	%	92.3	%	2.4	%	(0.3	)%	92.6	%	92.7	%	(0.1	)%

(1) Fleet horsepower is horsepower for compression units that have been delivered to us (and excludes units on order). As of March 22, 2013, 19,280 horsepower had been delivered and 6,900 horsepower is expected to be delivered in the remainder of March 2013, and 61,795 horsepower between April 2013 and August 2013.

(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 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 a 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 horsepower per revenue generating horsepower for each of the months in the period.

(5) Calculated as the average of the month-end horsepower per revenue generating compression unit for each of the months in the period.

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Horsepower utilization based on revenue generating horsepower and fleet horsepower at each applicable period end was 86.4%, 89.9%, 87.5% and 86.2%, for the years ended December 31, 2012, 2011, 2010 and 2009, respectively.

(7) Calculated as the average utilization for the months in the period based on utilization at the end of each month in the period.

A substantial majority of our compression units have electronic control systems that enable us, if specified by our customers, to monitor our units remotely by satellite or other means to supplement our technicians’ on-site monitoring visits. Our compression units are designed to automatically shut down if operating conditions deviate from a pre-determined range. While we retain the care, custody, ongoing maintenance and control of our compression units, we allow our customers, subject to a defined protocol, to start, stop, accelerate and slow down compression units in response to field conditions.

We adhere to routine, preventive and scheduled maintenance cycles. Each of our compression units is subjected to rigorous sizing and diagnostic analyses, including lubricating oil analysis and engine exhaust emission analysis. We have proprietary field service automation capabilities that allow our service technicians to electronically record and track operating, technical, environmental and commercial information at the discrete unit level. These capabilities allow our field technicians to identify potential problems and act on them before such problems result in downtime.

Generally, we expect each of our compression units to undergo a major overhaul between service deployment cycles once every eight to ten years for our larger horsepower units (500 horsepower or more) and on average every five years for smaller horsepower units. A major overhaul involves the periodic rebuilding of the unit to materially extend its economic useful life or to enhance the unit’s ability to fulfill broader or more diversified compression applications. Because our compression fleet is comprised of units of varying horsepower that have been placed into service with staggered initial on-line dates, we expect that we will be able to schedule overhauls in a way to avoid excessive maintenance capital expenditures and minimize the revenue impact of downtime.

We believe that our customers, by outsourcing their compression requirements, can increase their revenue by transporting or producing a higher volume of natural gas through decreased compression downtime and reduce their operating, maintenance and equipment costs by allowing us to manage efficiently their changing compression needs. We generally guarantee our customers availability ranging from 95% to 98%, depending on field level requirements.

General Compression Service Contract Terms

The following discussion describes the material terms generally common to our compression service contracts. We generally enter into a new contract with respect to each distinct application for which we will provide compression services.

Term and termination. Our contracts typically have an initial term between one and five years, after which the contract continues on a month-to-month basis until terminated by us or our customers upon notice as provided for in the applicable contract.

Availability. Our contracts often provide a guarantee of specified availability. We define availability as the percentage of time in a given period that our compression services are being provided or are capable of being provided. Availability is reduced by instances of “down-time” that are attributable to anything other than events of force majeure or acts or failures to act by the customer. “Down-time” under our contracts usually begins when our services stop being provided and when we receive notice of the problem. Down-time due to scheduled maintenance is also excluded from our availability commitment. As a consequence of our availability guarantee, we are incentivized to practice predictive and preventive maintenance on our fleet as well as promptly respond to a problem to meet our contractual commitments and ensure our customers the compression availability on which their business and our service relationship is based.

Fees and expenses. Our customers pay a fixed monthly fee for our services. We bill our customers 30 days in advance, and they are required to pay upon receipt of the invoice. We are not responsible for acts of force majeure, and our customers generally are required to pay our monthly fee even during periods of limited or disrupted throughput. We are generally responsible for the costs and expenses associated with operation and maintenance of our compression equipment, such as providing necessary lubricants, although certain fees and expenses are the responsibility of our customers under the terms of their contracts. For example, all fuel gas is provided by our customers without cost to us, and in many cases customers are required to provide all water and electricity, while lubricants in certain cases may be provided by the customer. We are also reimbursed by our customers for certain ancillary expenses such as trucking and crane, depending on the terms agreed to in the applicable contract, resulting in no gross operating margin.

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Service standards and specifications. We commit to provide compression services under service contracts that typically provide that we will supply all compression equipment, tools, parts, field service support and engineering. Our contracts do not govern the compression equipment we will use; instead, we determine what equipment is necessary to perform our contractual commitments.

Title; Risk of loss. We own or lease all compression equipment we use to provide compression services, and we normally bear the risk of loss or damage to our equipment and tools and injury or death to our personnel.

Insurance. Our contracts typically provide that both we and our customers are required to carry general liability, worker’s compensation, employers’ liability, automobile and excess liability insurance.

Marketing and Sales

Our marketing and client service functions are performed on a coordinated basis by our sales and field technicians. Salespeople and field technicians qualify, analyze and scope new compression applications as well as regularly visit our customers to ensure customer satisfaction, to determine a customer’s current needs related to services currently being provided and to determine the customer’s future compression services requirements. This ongoing communication allows us to quickly identify and respond to our customers’ compression requirements. We currently focus on geographic areas where we can achieve economies of scale through high density operations.

Customers

Our customers consist of more than 110 companies in the energy industry, including major integrated oil companies, public and private independent exploration and production companies and midstream companies. Our largest customer for the years ended December 31, 2012 and 2011 was Southwestern Energy Corporation and its subsidiaries, or Southwestern Energy. Southwestern Energy accounted for 14.5% of our revenue for the year ended December 31, 2012 and 15.9% of our revenues for the year ended December 31, 2011. Our ten largest customers accounted for 54% and 53% of our revenues for the years ended December 31, 2012 and 2011, respectively.

Suppliers and Service Providers

The principal manufacturers of components for our natural gas compression equipment include Caterpillar, Inc. or Caterpillar (for engines), Air-X-Changers and Air Cooled Exchangers (for coolers), and Ariel Corporation (for compressor frames and cylinders). We also rely primarily on two vendors, A G Equipment Company and Standard Equipment Corp., to package and assemble our compression units. Although we rely primarily on these suppliers, we believe alternative sources for natural gas compression equipment are generally available if needed. However, relying on alternative sources may change the standardized nature of our fleet. We have not experienced any material supply problems to date, although lead-times for Caterpillar engines have in the past been in excess of one year due to increased demand and supply allocations imposed on equipment packagers and end-users by Caterpillar.

Competition

The compression services business is highly competitive. Some of our competitors have a broader geographic scope, as well as greater financial and other resources than we do. On a regional basis, we experience competition from numerous smaller companies that may be able to more quickly adapt to changes within our industry and changes in economic conditions as a whole, more readily take advantage of available opportunities and adopt more aggressive pricing policies. Additionally, the current availability of attractive financing terms from financial institutions and equipment manufacturers makes the purchase of individual compression units increasingly affordable to our customers. We believe that we compete effectively on the basis of price, equipment availability, customer service, flexibility in meeting customer needs, quality and reliability of our compressors and related services.

Seasonality

Our results of operations have not historically reflected any material seasonality, and we do not currently have reason to believe seasonal fluctuations will have a material impact in the foreseeable future.

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Insurance

We believe that our insurance coverage is customary for the industry and adequate for our business. As is customary in the natural gas services industry, we review our safety equipment and procedures and carry insurance against most, but not all, risks of our business. Losses and liabilities not covered by insurance would increase our costs. The compression business can be hazardous, involving unforeseen circumstances such as uncontrollable flows of gas or well fluids, fires and explosions or environmental damage. To address the hazards inherent in our business, we maintain insurance coverage that includes physical damage coverage, third party general liability insurance, employer’s liability, environmental and pollution and other coverage, although coverage for environmental and pollution related losses is subject to significant limitations. Under the terms of our standard compression services contract, we are responsible for the maintenance of insurance coverage on our compression equipment.

Environmental and Safety Regulations

We are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of human health, safety and the environment. These regulations include compliance obligations for air emissions, water quality, wastewater discharges and solid and hazardous waste disposal, as well as regulations designed for the protection of human health and safety and threatened or endangered species. Compliance with these environmental laws and regulations may expose us to significant costs and liabilities and cause us to incur significant capital expenditures in our operations. We are often obligated to obtain permits or approvals in our operations from various federal, state and local authorities, which permits and approvals can be denied or delayed, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenue. Moreover, failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of remedial obligations, and the issuance of injunctions delaying or prohibiting operations. Private parties may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. While we believe that our operations are in substantial compliance with applicable environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on us, there is no assurance that this trend of compliance will continue in the future. In addition, the clear trend in environmental regulation is to place more restrictions on activities that may affect the environment, and thus, any changes in, or more stringent enforcement of, these laws and regulations that result in more stringent and costly pollution control equipment, waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial position.

We do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations or cash flows. We cannot assure you, however, that future events, such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations or the development or discovery of new facts or conditions or unforeseen incidents will not cause us to incur significant costs. The following is a discussion of material environmental and safety laws that relate to our operations. We believe that we are in substantial compliance with all of these environmental laws and regulations.

Air emissions. The CAA and comparable state laws regulate emissions of air pollutants from various industrial sources, including natural gas compressors, and also impose certain monitoring and reporting requirements. Such emissions are regulated by air emissions permits, which are applied for and obtained through the various state or federal regulatory agencies. Our standard natural gas compression contract typically provides that the customer is responsible for obtaining air emissions permits and assuming the environmental risks related to site operations. Increased obligations of operators to reduce air emissions of nitrogen oxides and other pollutants from internal combustion engines in transmission service have been enacted by governmental authorities. For example, on August 20, 2010, the EPA published new regulations under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocal internal combustion engines, also known as Quad Z regulations. On June 7, 2012, the EPA proposed amendments to the final rule in response to several petitions for reconsideration. The EPA finalized the proposed amendments on January 30, 2013. The rule will require us to undertake certain expenditures and activities, likely including purchasing and installing emissions control equipment on certain compressor engines and generators. The final rule is effective on April 1, 2013, and imposes varying compliance deadlines based on engine rating and type of site, with the latest deadlines falling on October 19, 2013. We are currently evaluating the impact that the final rule will have on our operations but we do not believe that the costs associated with achieving compliance with the final rule will be material.

On June 28, 2011, the EPA issued a final rule, effective August 29, 2011, modifying existing regulations under the CAA that established new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines, also known as Quad J regulations. The final rule may require us to undertake significant expenditures,

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including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment. On June 7, 2012, the EPA proposed minor amendments in order to conform the final rule to the proposed amendments to the Quad Z regulations. These amendments were finalized on January 30, 2013, with an effective date of April 1, 2013. We are currently evaluating the impact that these rules will have on our operations.

In March 2008, the EPA also promulgated a new, lower National Ambient Air Quality Standard, or NAAQS, for ozone. While the EPA announced in September 2009 that it would reconsider the 2008 NAAQS for ozone, it withdrew the reconsideration on September 2, 2011. Under the CAA, the EPA will be required to review and potentially issue a new NAAQS for ground level ozone in 2013. In addition, on January 15, 2013, the EPA promulgated a final rule revising the annual standard for PM2.5 by lowering the level from 15 to 12 micrograms per cubic meter. EPA does not anticipate making initial attainment or nonattainment designations until December 2014. Designation of new non-attainment areas for the revised ozone or PM2.5 NAAQS may result in additional federal and state regulatory actions that could impact our customers’ operations and increase the cost of additions to property, plant and equipment.

On April 17, 2012, the EPA finalized rules that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The rules establish specific new requirements regarding emissions from compressors and controllers at natural gas processing plants, dehydrators, storage tanks and other production equipment. In addition, the rules establish new leak detection requirements for natural gas processing plants at 500 ppm. These rules may require a number of modifications to our operations, including the installation of new equipment to control emissions from our compressors at initial startup. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

In addition, the Texas Commission on Environmental Quality, or TCEQ, has finalized revisions to certain air permit programs that significantly increase the air permitting requirements for new and certain existing oil and gas production and gathering sites for 15 counties in the Barnett Shale production area. The final rule establishes new emissions standards for engines, which could impact the operation of specific categories of engines by requiring the use of alternative engines, compressor packages or the installation of aftermarket emissions control equipment. The rule became effective for the Barnett Shale production area in April 2011, with the lower emissions standards becoming applicable between 2015 and 2030 depending on the type of engine and the permitting requirements. The cost to comply with the revised air permit programs is not expected to be material at this time. However, the TCEQ has stated it will consider expanding application of the new air permit program statewide. At this point, we cannot predict the cost to comply with such requirements if the geographic scope is expanded.

There can be no assurance that future requirements compelling the installation of more sophisticated emission control equipment would not have a material adverse impact on our business, financial condition, results of operations and ability to make cash distributions to our unitholders.

Climate change. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas, are examples of greenhouse gases, or GHGs. In recent years, the U.S. Congress has considered legislation to reduce emissions of GHGs. It presently appears unlikely that comprehensive climate legislation will be passed by either house of Congress in the near future, although energy legislation and other initiatives are expected to be proposed that may be relevant to GHG emissions issues. In addition, almost half of the states have begun to address GHG emissions, primarily through the planned development of emission inventories or regional GHG cap and trade programs. Depending on the particular program, we could be required to control GHG emissions or to purchase and surrender allowances for GHG emissions resulting from our operations.

Independent of Congress, the U.S. Environmental Protection Agency, or the EPA, is beginning to adopt regulations controlling GHG emissions under its existing Clean Air Act authority. For example, on December 15, 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. In 2009, the EPA adopted rules regarding regulation of GHG emissions from motor vehicles. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of GHG emissions in the United States beginning in 2011 for emissions occurring in 2010 from specified large GHG emission sources. On November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule for petroleum and natural gas facilities, including natural gas transmission compression facilities that emit 25,000 metric tons or more of

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carbon dioxide equivalent per year. The rule, which went into effect on December 30, 2010, requires reporting of GHG emissions by such regulated facilities to the EPA by September 2012 for emissions during 2011 and annually thereafter. In 2010, the EPA also issued a final rule, known as the “Tailoring Rule,” that makes certain large stationary sources and modification projects subject to permitting requirements for GHG emissions under the Clean Air Act. On June 26, 2012, a federal appeals court dismissed all challenges to the EPA’s authority to regulate GHG emissions, which means that the EPA may develop new rules in the future to control GHG emissions — although numerous parties are expected to seek review of the federal appellate court’s decision with the United States Supreme Court.

Although it is not currently possible to predict how any such proposed or future greenhouse gas legislation or regulation by Congress, the states or multi-state regions will impact our business, any legislation or regulation of greenhouse gas emissions that may be imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions or reduced demand for our services, and could have a material adverse effect on our business, financial condition and results of operations.

Water discharge. The Clean Water Act, or CWA, and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. The CWA also requires the development and implementation of spill prevention, control, and countermeasures, including the construction and maintenance of containment berms and similar structures, if required, to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak at such facilities. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. Our compression operations do not generate process wastewaters that are discharged to waters of the U.S. In any event, our customers assume responsibility under our standard natural gas compression contract for obtaining any discharge permits that may be required under the CWA.

Safe Drinking Water Act. A portion of our customers’ natural gas production is developed from unconventional sources that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gas production. Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the Safe Drinking Water Act. Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a multi-year study of the potential environmental impacts of hydraulic fracturing, the results of which are anticipated to be available in 2014. EPA also has recently announced that it believes hydraulic fracturing using fluids containing diesel fuel can be regulated under the SDWA notwithstanding the SDWA’s general exemption for hydraulic fracturing. Several states have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. We cannot predict the future of such legislation and what additional, if any, provisions would be. If additional levels of regulation, restrictions and permits were required through the adoption of new laws and regulations at the federal or state level, that could lead to delays, increased operating costs and process prohibitions that could reduce demand for our compression services, which would materially adversely affect our revenue and results of operations.

Solid waste. The Resource Conservation and Recovery Act, or the RCRA, and comparable state laws control the management and disposal of hazardous and non-hazardous waste. These laws and regulations govern the generation, storage, treatment, transfer and disposal of wastes that we generate including, but not limited to, used oil, antifreeze, filters, sludges, paint, solvents, and sandblast materials. The EPA and various state agencies have limited the approved methods of disposal for these types of wastes.

Site remediation. The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, and comparable state laws impose strict, joint and several liability without regard to fault or the legality of the original conduct on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include the owner and operator of a disposal site where a hazardous substance release occurred and any company that transported, disposed of, or arranged for the transport or disposal of hazardous substances released at the site. Under CERCLA, such persons may be liable for the costs of remediating the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. In addition, where contamination may be present, it is not uncommon for the neighboring landowners and

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other third parties to file claims for personal injury, property damage and recovery of response costs. While we generate materials in the course of our operations that may be regulated as hazardous substances, we have not received notification that we may be potentially responsible for cleanup costs under CERCLA at any site.

While we do not currently own or lease any material facilities or properties for storage or maintenance of our inactive compression units, we may use third party properties for such storage and possible maintenance and repair activities. In addition, our active compression units typically are placed on properties owned or leased by third party customers and operated by us pursuant to terms set forth in the natural gas compression services contracts executed by those customers. Under most of our natural gas compression services contracts, our customers must contractually indemnify us for certain damages we may suffer as a result of the release into the environment of hazardous and toxic substances. We are not currently responsible for any remedial activities at any properties used by us; however, there is always the possibility that our future use of those properties may result in spills or releases of petroleum hydrocarbons, wastes, or other regulated substances into the environment that may cause us to become subject to remediation costs and liabilities under CERCLA, RCRA or other environmental laws. We cannot provide any assurance that the costs and liabilities associated with the future imposition of such remedial obligations upon us would not have a material adverse effect on our operations or financial position.

Safety and health. The Occupational Safety and Health Act, or OSHA, and comparable state laws strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that we organize and, as necessary, disclose information about hazardous materials used or produced in our operations to various federal, state and local agencies, as well as employees.

Properties

We do not currently own or lease any material facilities or properties for storage or maintenance of our compression units. As of December 31, 2012, our headquarters consisted of 9,378 square feet of leased space located at 100 Congress Avenue, Austin, Texas 78701.

Employees

We are managed and operated by the officers and directors of USA Compression GP, LLC, our general partner. As of December 31, 2012, we employed 240 people either directly or through USAC Operating. None of our employees are subject to collective bargaining agreements. We consider our employee relations to be good.

Legal Proceedings

From time to time we may be involved in litigation relating to claims arising out of our operations in the normal course of business. We are not currently a party to any legal proceedings that we believe would have a material adverse effect on our financial position, results of operations or cash flows.

ITEM 1A. Risk Factors

As described in Part I (“Disclosure Regarding Forward-Looking Statements”), this report contains forward-looking statements regarding us, our business and our industry. The risk factors described below, among others, could cause our actual results to differ materially from the expectations reflected in the forward-looking statements. If any of the following risks were to occur, our business, financial condition or results of operations could be materially and adversely affected. In that case, we might not be able to pay our minimum quarterly distribution on our common units or grow such distributions and the trading price of our common units could decline.

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Risks Related to Our Business

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay our minimum quarterly distributions to holders of our common units and subordinated units.

In order to pay our minimum quarterly distribution of $0.425 per unit per quarter, or $1.70 per unit per year, we will require available cash of $12.6 million per quarter, or $50.5 million per year, based on the number of common units, subordinated units and the 2.0% general partner interest currently outstanding. Under our cash distribution policy, the amount of cash we can distribute to our unitholders principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

· the level of production of, demand for, and price of natural gas and crude oil, particularly the level of production in the locations where we provide compression services;

· the fees we charge, and the margins we realize, from our compression services;

· the cost of achieving organic growth in current and new markets;

· the level of competition from other companies; and

· prevailing global and regional economic and regulatory conditions, and their impact on our customers.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, including:

· the levels of our maintenance capital expenditures and expansion capital expenditures;

· the level of our operating costs and expenses;

· our debt service requirements and other liabilities;

· fluctuations in our working capital needs;

· restrictions contained in our revolving credit facility;

· the cost of acquisitions, if any;

· fluctuations in interest rates;

· our ability to borrow funds and access capital markets; and

· the amount of cash reserves established by our general partner.

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 our unitholders.

The demand for our compression services depends upon the continued demand for, and production of, natural gas and crude oil. Demand may be affected by, among other factors, natural gas prices, crude oil prices, weather, availability of alternative energy sources, governmental regulation and general demand for energy. Any prolonged, substantial reduction in the demand for natural gas or crude oil would, in all likelihood, depress the level of production activity and result in a decline in the demand for our compression services, which would reduce our cash available for distribution. Lower natural gas prices or crude oil prices over the long term could result in a decline in the production of natural gas or crude oil, respectively, resulting in reduced demand for our compression services. Additionally, production from unconventional natural gas sources, such as tight sands, shales and coalbeds, constitute an increasing

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percentage of our compression services business. Such sources can be less economically feasible to produce in low natural gas price environments, in part due to costs related to compression requirements, and a reduction in demand for natural gas or natural gas lift for crude oil may cause such sources of natural gas to be uneconomic to drill and produce, which could in turn negatively impact the demand for our services. In addition, governmental regulation and tax policy may impact the demand for natural gas or impact the economic feasibility of development of new natural gas fields or production of existing fields.

We have several key customers. The loss of any of these customers would result in a decrease in our revenues and cash available for distribution to our unitholders.

We provide compression services under contracts with several key customers. The loss of one of these key customers may have a greater effect on our financial results than for a company with a more diverse customer base. Our largest customer for the years ended December 31, 2012 and 2011 was Southwestern Energy Company and its subsidiaries, or Southwestern Energy. Southwestern Energy accounted for 14.5% of our revenue for the year ended December 31, 2012 and 15.9% of our revenues for the year ended December 31, 2011. Our ten largest customers accounted for 54% and 53% of our revenues for the year ended December 31, 2012 and 2011, respectively. The loss of all or even a portion of the compression services we provide to our key customers, as a result of competition or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

The erosion of the financial condition of our customers could adversely affect our business.

During times when the natural gas or oil markets weaken, our customers are more likely to experience financial difficulties and the lack of availability of debt or equity financing, which could result in a reduction in our customers’ spending for our services. For example, our customers could seek to preserve capital by using lower cost providers, not renewing month-to-month contracts or determining not to enter into any new compression service contracts. Reduced demand for our services could adversely affect our business, results of operations, financial condition and cash flows. In addition, in the event of the financial failure of a customer, we could experience a loss of all or a portion of our outstanding accounts receivable associated with that customer.

We face significant competition that may cause us to lose market share and reduce our ability to make distributions to our unitholders.

The compression business is highly competitive. Some of our competitors have a broader geographic scope, as well as greater financial and other resources than we do. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenue and cash flows could be adversely affected by the activities of our competitors and our customers. If our competitors substantially increase the resources they devote to the development and marketing of competitive services or substantially decrease the prices at which they offer their services, we may be unable to compete effectively. Some of these competitors may expand or construct newer, more powerful or more flexible compression fleets that would create additional competition for us. Additionally, there are lower barriers to entry for customers as competitors seeking to purchase individual compression units. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and reduce our ability to make cash distributions to our unitholders.

Our customers may choose to vertically integrate their operations by purchasing and operating their own compression fleet, or expanding the amount of compression units they currently own.

Our customers that are significant producers, processors, gatherers and transporters of natural gas and crude oil may choose to vertically integrate their operations by purchasing and operating their own compression fleets in lieu of using our compression services. Currently, the availability of attractive financing terms from financial institutions and equipment manufacturers facilitates this possibility by making the purchase of individual compression units increasingly affordable to our customers. Such vertical integration or increases in vertical integration could result in decreased demand for our compression services, which may have a material adverse effect on our business, results of operations, financial condition and reduce our ability to make cash distributions to our unitholders.

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A significant portion of our services are provided to customers on a month-to-month basis, and we cannot be sure that our customers will continue to utilize these services that have continued beyond the primary term.

As of December 31, 2012, approximately 35% of our compression services on a horsepower basis (and 38% on a revenue basis for the year ended December 31, 2012) were provided on a month-to-month basis to customers who continue to utilize our services following expiration of the primary term of their contracts with us. These customers can generally terminate their month-to-month compression services contracts on 30-days’ written notice. If a significant number of these customers were to terminate their month-to-month services, or attempt to renegotiate their month-to-month contracts at substantially lower rates, it could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

We may be unable to grow our cash flows if we are unable to expand our business, which could limit our ability to increase distributions to our unitholders.

A principal focus of our strategy is to continue to grow the per unit distribution on our units by expanding our business. Our future growth will depend upon a number of factors, some of which we cannot control. These factors include our ability to:

· develop new business and enter into service contracts with new customers;

· retain our existing customers and maintain or expand the services we provide them;

· recruit and train qualified personnel and retain valued employees;

· expand our geographic presence;

· effectively manage our costs and expenses, including costs and expenses related to growth;

· consummate accretive acquisitions;

· obtain required debt or equity financing for our existing and new operations; and

· meet customer specific contract requirements or pre qualifications.

If we do not achieve our expected growth, we may not be able to pay the aggregate minimum quarterly distribution on our common units and subordinated units and the 2.0% general partner interest, in which event the market price of our common units will likely decline materially.

We may be unable to grow successfully through future acquisitions, and we may not be able to integrate effectively the businesses we may acquire, which may impact our operations and limit our ability to increase distributions to our unitholders.

From time to time, we may choose to make business acquisitions to pursue market opportunities, increase our existing capabilities and expand into new areas of operations. While we have reviewed acquisition opportunities in the past and will continue to do so in the future, we may not be able to identify attractive acquisition opportunities or successfully acquire identified targets. In addition, we may not be successful in integrating any future acquisitions into our existing operations, which may result in unforeseen operational difficulties or diminished financial performance or require a disproportionate amount of our management’s attention. Even if we are successful in integrating future acquisitions into our existing operations, we may not derive the benefits, such as operational or administrative synergies, that we expected from such acquisitions, which may result in the commitment of our capital resources without the expected returns on such capital. Furthermore, competition for acquisition opportunities may escalate, increasing our cost of making acquisitions or causing us to refrain from making acquisitions. Our inability to make acquisitions, or to integrate successfully future acquisitions into our existing operations, may adversely impact our operations and limit our ability to increase distributions to our unitholders.

Our ability to grow in the future is dependent on our ability to access external expansion capital.

We will distribute all of our available cash after expenses and prudent operating reserves to our unitholders. We expect that we will rely primarily upon external financing sources, including borrowings under our revolving credit facility and the issuance of

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debt and equity securities, to fund expansion capital expenditures. However, we may not be able to obtain equity or debt financing on terms favorable to us, or at all. To the extent we are unable to efficiently finance growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we distribute all of our available cash, we may not grow as quickly as businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with other expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of borrowings or other debt by us to finance our growth strategy would result in interest expense, which in turn would affect the available cash that we have to distribute to our unitholders.

Our ability to manage and grow our business effectively may be adversely affected if we lose management or operational personnel.

We depend on the continuing efforts of our executive officers. The departure of any of our executive officers, and in particular, Eric D. Long, President and Chief Executive Officer of our general partner, could have a significant negative effect on our business, operating results, financial condition and on our ability to compete effectively in the marketplace.

Additionally, our ability to hire, train and retain qualified personnel will continue to be important and will become more challenging as we grow and if energy industry market conditions continue to be positive. When general industry conditions are good, the competition for experienced operational and field technicians increases as other energy and manufacturing companies’ needs for the same personnel increases. Our ability to grow or even to continue our current level of service to our current customers will be adversely impacted if we are unable to successfully hire, train and retain these important personnel.

We depend on a limited number of suppliers and are vulnerable to product shortages and price increases, which could have a negative impact on our results of operations.

The substantial majority of the components for our natural gas compression equipment are supplied by Caterpillar, Inc. (for engines), Air-X-Changers and Air Cooled Exchangers (for coolers), and Ariel Corporation (for compressor frames and cylinders). Our reliance on these suppliers involves several risks, including price increases and a potential inability to obtain an adequate supply of required components in a timely manner. We also rely primarily on two vendors, A G Equipment Company and Standard Equipment Corp., to package and assemble our compression units. We do not have long-term contracts with these suppliers or packagers, and a partial or complete loss of any of these sources could have a negative impact on our results of operations and could damage our customer relationships. Some of these suppliers manufacture the components we purchase in a single facility, and any damage to that facility could lead to significant delays in delivery of completed units. In addition, since we expect any increase in component prices for compression equipment or packaging costs will be passed on to us, a significant increase in their pricing could have a negative impact on our results of operations.

We are subject to substantial environmental regulation, and changes in these regulations could increase our costs or liabilities.

We are subject to stringent and complex federal, state and local laws and regulations, including laws and regulations regarding the discharge of materials into the environment, emission controls and other environmental protection and occupational health and safety concerns. Environmental laws and regulations may, in certain circumstances, impose strict liability for environmental contamination, which may render us liable for remediation costs, natural resource damages and other damages as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior owners or operators or other third parties. In addition, where contamination may be present, it is not uncommon for neighboring land owners and other third parties to file claims for personal injury, property damage and recovery of response costs. Remediation costs and other damages arising as a result of environmental laws and regulations, and costs associated with new information, changes in existing environmental laws and regulations or the adoption of new environmental laws and regulations could be substantial and could negatively impact our financial condition or results of operations. Moreover, failure to comply with these environmental laws and regulations may result in the imposition of administrative, civil and criminal penalties and the issuance of injunctions delaying or prohibiting operations.

We conduct operations in a wide variety of locations across the continental U.S. These operations require U.S. federal, state or local environmental permits or other authorizations. Our operations may require new or amended facility permits or licenses from time to time with respect to storm water discharges, waste handling, or air emissions relating to equipment operations, which subject us to new or revised permitting conditions that may be onerous or costly to comply with. Additionally, the operation of compression

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units may require individual air permits or general authorizations to operate under various air regulatory programs established by rule or regulation. These permits and authorizations frequently contain numerous compliance requirements, including monitoring and reporting obligations and operational restrictions, such as emission limits. Given the wide variety of locations in which we operate, and the numerous environmental permits and other authorizations that are applicable to our operations, we may occasionally identify or be notified of technical violations of certain requirements existing in various permits or other authorizations. We could be subject to penalties for any noncompliance in the future.

We routinely deal with natural gas, oil and other petroleum products. Hydrocarbons or other hazardous substances or wastes may have been disposed or released on, under or from properties used by us to provide compression services or inactive compression unit storage or on or under other locations where such substances or wastes have been taken for disposal. These properties may be subject to investigatory, remediation and monitoring requirements under federal, state and local environmental laws and regulations.

The modification or interpretation of existing environmental laws or regulations, the more vigorous enforcement of existing environmental laws or regulations, or the adoption of new environmental laws or regulations may also negatively impact oil and natural gas exploration and production, gathering and pipeline companies, including our customers, which in turn could have a negative impact on us.

New regulations, proposed regulations and proposed modifications to existing regulations under the Clean Air Act, or CAA, if implemented, could result in increased compliance costs.

On August 20, 2010, the U.S. Environmental Protection Agency, or the EPA, published new regulations under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocating internal combustion engines. On June 7, 2012, the EPA proposed amendments to the final rule in response to several petitions for reconsideration, and the EPA finalized the proposed amendments on January 30, 2013. The final rule is effective on April 1, 2013, and imposes varying compliance deadlines based on engine ratings and type of site, with the latest deadlines falling on October 19, 2013. The rule will require us to undertake certain expenditures and activities, including purchasing and installing emissions control equipment on a portion of our engines located at major sources of hazardous air pollutants, following prescribed maintenance practices for engines (which are consistent with our existing practices), and implementing additional emissions testing and monitoring. We do not believe the costs associated with achieving compliance with the final rule will be material to our business, financial condition, results of operations or ability to make cash distributions to our unitholders.

On June 28, 2011, the EPA issued a final rule modifying existing regulations under the CAA that established new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. The final rule will require us to undertake certain expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment on some of our natural gas compression fleet. On June 7, 2012, the EPA proposed minor amendments in order to conform the final rule to the proposed amendments to the Quad Z regulations, and the EPA finalized those amendments on January 30, 2013, with an effective date of April 1, 2013. We are currently evaluating the impact that this final rule and proposed amendments will have on our operations.

On April 17, 2012 the EPA finalized rules that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The rules establish specific new requirements regarding emissions from compressors and controllers at natural gas processing plants, dehydrators, storage tanks and other production equipment. In addition, the rules establish more stringent leak detection minimum thresholds for natural gas processing plants at 500 ppm for VOCs. These rules may require a number of modifications to our operations, including the installation of new equipment to control emissions from our compressors at initial startup. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

In addition, the Texas Commission on Environmental Quality, or the TCEQ, has finalized revisions to certain air permit programs that significantly increase the air permitting requirements for new and certain existing oil and gas production and gathering sites for 15 counties in the Barnett Shale production area. The final rule establishes new emissions standards for engines, which could impact the operation of specific categories of engines by requiring the use of alternative engines, compression packages or the installation of aftermarket emissions control equipment. The rule became effective for the Barnett Shale production area in April 2011, with the lower emissions standards becoming applicable between 2015 and 2030 depending on the type of engine and the permitting requirements. The cost to comply with the revised air permit programs is not expected to be material at this time. However, the TCEQ

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has stated it will consider expanding application of the new air permit program statewide. At this point, we cannot predict the cost to comply with such requirements if the geographic scope is expanded.

These new regulations and proposals, when finalized, and any other new regulations requiring the installation of more sophisticated pollution control equipment could have a material adverse impact on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

Climate change legislation and regulatory initiatives could result in increased compliance costs.

Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas, are examples of greenhouse gases, or GHGs. In recent years, the U.S. Congress has considered legislation to reduce emissions of GHGs. It presently appears unlikely that comprehensive climate legislation will be passed by either house of Congress in the near future, although energy legislation and other initiatives are expected to be proposed that may be relevant to GHG emissions issues. In addition, almost half of the states have begun to address GHG emissions, primarily through the planned development of emission inventories or regional GHG cap and trade programs. Depending on the particular program, we could be required to control GHG emissions or to purchase and surrender allowances for GHG emissions resulting from our operations.

Independent of Congress, the EPA is beginning to adopt regulations controlling GHG emissions under its existing Clean Air Act authority. For example, on December 15, 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. In 2009, the EPA adopted rules regarding regulation of GHG emissions from motor vehicles. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of GHG emissions in the United States beginning in 2011 for emissions occurring in 2010 from specified large GHG emission sources. On November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule for petroleum and natural gas facilities, including natural gas transmission compression facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year. The rule, which went into effect on December 30, 2010, requires reporting of GHG emissions by such regulated facilities to the EPA by September 2012 for emissions during 2011 and annually thereafter. In 2010, the EPA also issued a final rule, known as the “Tailoring Rule,” that makes certain large stationary sources and modification projects subject to permitting requirements for GHG emissions under the Clean Air Act. On June 26, 2012, a federal appeals court dismissed all challenges to the EPA’s authority to regulate GHG emissions, which could mean that the EPA may develop new rules related to GHG emissions in the future — although numerous parties are expected to seek review of the federal appellate court’s decision with the United States Supreme Court in 2013. This new permitting program may affect some of our customers’ largest new or modified facilities going forward.

Although it is not currently possible to predict how any such proposed or future GHG legislation or regulation by Congress, the states or multi state regions will impact our business, any legislation or regulation of GHG emissions that may be imposed in areas in which we conduct business could result in increased compliance costs, additional operating restrictions or reduced demand for our services, and could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production by our customers, which could adversely impact our revenue.

A portion of our customers’ natural gas production is from unconventional sources that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gas production. Legislation to amend the Safe Drinking Water Act, or SDWA, to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the Safe Drinking Water Act. Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a multi-year study of the potential environmental impacts of hydraulic fracturing, the results of which are anticipated to be available in 2014. The EPA also has recently announced that it believes hydraulic fracturing using fluids containing diesel fuel can be regulated under the SDWA notwithstanding the SDWA’s general exemption for hydraulic fracturing. Several states have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. We cannot predict if additional legislation will ever be enacted and if so, what its provisions would be. If additional levels of regulation, restriction and permits were required through the adoption of new laws and

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regulations at the federal or state level, that could lead to delays, increased operating costs and process prohibitions that could reduce demand for our compression services, which could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our unitholders.

We do not insure against all potential losses and could be seriously harmed by unexpected liabilities.

Our operations are subject to inherent risks such as equipment defects, malfunction and failures, and natural disasters that can result in uncontrollable flows of gas or well fluids, fires and explosions. These risks could expose us to substantial liability for personal injury, death, property damage, pollution and other environmental damages. Our insurance may be inadequate to cover our liabilities. Further, insurance covering the risks we face or in the amounts we desire may not be available in the future or, if available, the premiums may not be commercially justifiable. If we were to incur substantial liability and such damages were not covered by insurance or were in excess of policy limits, or if we were to incur liability at a time when we are not able to obtain liability insurance, our business, results of operations and financial condition could be adversely affected. Please read “Business—Our Operations—Environmental and Safety Regulations” for a description of how we are subject to federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of human health and environment.

Our debt levels may limit our flexibility in obtaining additional financing, pursuing other business opportunities and paying distributions.

We have a $600 million revolving credit facility that matures on October 5, 2015. In addition, we have the option to increase the amount of available borrowings under the revolving credit facility by $50 million, subject to receipt of lender commitments and satisfaction of other conditions. Our ability to incur additional debt is subject to limitations in our revolving credit facility. Our level of debt could have important consequences to us, including the following:

· our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

· we will need a portion of our cash flow to make payments on our indebtedness, reducing the funds that would otherwise be available for operation, future business opportunities and distributions; and

· our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. In addition, our ability to service our debt under the revolving credit facility will depend on market interest rates, since we anticipate that the interest rates applicable to our borrowings will fluctuate with movements in interest rate markets. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional equity capital. We may be unable to effect any of these actions on satisfactory terms, or at all.

Restrictions in our revolving credit facility may limit our ability to make distributions to our unitholders and may limit our ability to capitalize on acquisition and other business opportunities.

The operating and financial restrictions and covenants in our revolving credit facility and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities. Our amended and restated credit agreement restricts or limits our ability to:

· grant liens;

· make certain loans or investments;

· incur additional indebtedness or guarantee other indebtedness;

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· subject to exceptions, enter into transactions with affiliates;

· sell our assets; and

· acquire additional assets.

Furthermore, our revolving credit facility contains certain operating and financial covenants. Our ability to comply with the covenants and restrictions contained in the revolving credit facility may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our revolving credit facility, a significant portion of our indebtedness may become immediately due and payable, our lenders’ commitment to make further loans to us may terminate, and we will be prohibited from making distributions to our unitholders. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. Any subsequent replacement of our revolving credit facility or any new indebtedness could have similar or greater restrictions. Please read Part II, Item 7 (“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Description of Revolving Credit Facility”).

An impairment of goodwill or other intangible assets could reduce our earnings.

We have recorded $157.1 million of goodwill and $81.6 million of other intangible assets as of December 31, 2012. Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets. GAAP requires us to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. Any event that causes a reduction in demand for our services could result in a reduction of our estimates of future cash flows and growth rates in our business. These events could cause us to record impairments of goodwill or other intangible assets. If we determine that any of our goodwill or other intangible assets are impaired, we will be required to take an immediate charge to earnings with a corresponding reduction of partners’ capital resulting in an increase in balance sheet leverage as measured by debt to total capitalization. There was no impairment recorded for goodwill or other intangible assets for the years ended December 31, 2012 and 2011.

Terrorist attacks, the threat of terrorist attacks, hostilities in the Middle East, or other sustained military campaigns may adversely impact our results of operations.

The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the magnitude of the threat of future terrorist attacks on the energy industry in general and on us in particular are not known at this time. Uncertainty surrounding hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of natural gas supplies and markets for natural gas and natural gas liquids and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.

If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.

Prior to our initial public offering, we had not been required to file reports with the SEC. In connection with the closing of our initial public offering, we became subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act. We prepare our consolidated financial statements in accordance with GAAP, but our internal accounting controls may not currently meet all standards applicable to companies with publicly traded securities. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded partnership. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002, or Section 404. For example, Section 404(a) will require us, among other things, to review and report annually on the effectiveness of our internal control over financial reporting. We must comply with Section 404(a) for our fiscal year ending December 31, 2013. In addition, our independent registered public accountants will be required to assess the effectiveness of internal control over financial reporting at the end of the fiscal year after we are no longer an “emerging growth company” under the Jumpstart Our Business Startups Act, which may be for up to five fiscal years after the completion of our initial public offering in

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January 2013. Any failure to develop, implement or maintain effective internal controls or to improve our internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our, or our independent registered public accounting firm’s conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. Ineffective internal controls will subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.

Risks Inherent in an Investment in Us

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. USA Compression Holdings is the sole member of our general partner and will have the right to appoint our general partner’s entire board of directors, including its independent directors. If the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

USA Compression Holdings owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including USA Compression Holdings, have conflicts of interest with us and limited fiduciary duties and they may favor their own interests to the detriment of us and our common unitholders.

USA Compression Holdings, which is principally owned and controlled by Riverstone, owns and controls our general partner and appointed all of the officers and directors of our general partner, some of whom are also officers and directors of USA Compression Holdings. Although our general partner has a fiduciary duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to its owners. Conflicts of interest will arise between USA Compression Holdings, Riverstone and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of USA Compression Holdings and the other owners of USA Compression Holdings over our interests and the interests of our common unitholders. These conflicts include the following situations, among others:

· neither our partnership agreement nor any other agreement requires USA Compression Holdings to pursue a business strategy that favors us;

· our general partner is allowed to take into account the interests of parties other than us, such as USA Compression Holdings, in resolving conflicts of interest;

· our partnership agreement limits the liability of and reduces the fiduciary duties owed by our general partner, and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;

· except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;

· our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership interests and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders;

· our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure,

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which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert to common units;

· our general partner determines which costs incurred by it are reimbursable by us;

· our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period;

· our partnership agreement permits us to classify up to $36.6 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our general partner in respect of the general partner interest or the incentive distribution rights;

· our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

· our general partner intends to limit its liability regarding our contractual and other obligations;

· our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units;

· our general partner controls the enforcement of the obligations that it and its affiliates owe to us;

· our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and

· our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

Our partnership agreement limits our general partner’s fiduciary duties to holders of our common and subordinated units.

Our partnership agreement contains provisions that modify and reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

· how to allocate business opportunities among us and its affiliates;

· whether to exercise its limited call right;

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· how to exercise its voting rights with respect to the units it owns;

· whether to elect to reset target distribution levels; and

· whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the provisions discussed above.

Even if holders of our common units are dissatisfied, they cannot remove our general partner without USA Compression Holdings’ consent.

The unitholders are currently unable to remove our general partner because our general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 662/3% of all outstanding common and subordinated units voting together as a single class is required to remove our general partner. USA Compression Holdings owns an aggregate of 62.2% of our outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period and no units held by the holders of the subordinated units or their affiliates (including the general partner and its affiliates) are voted in favor of that removal, all subordinated units will automatically be converted into common units. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business.

Our partnership agreement restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement:

· provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

· provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith, meaning that it believed that the decisions were in the best interest of our partnership;

· provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

· provides that our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is:

(a) approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval;

(b) approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;

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(c) on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

(d) fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in subclauses (c) and (d) above, then it will conclusively be deemed that, in making its decision, the board of directors acted in good faith.

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of the conflicts committee of its board of directors or the holders of our common units. This could result in lower distributions to holders of our common units.

Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution, and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units and to maintain its general partner interest. The number of common units to be issued to our general partner will equal the number of common units which would have entitled the holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. Our general partner’s general partner interest in us (currently 2.0%) will be maintained at the percentage that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units to our general partner in connection with resetting the target distribution levels.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Unitholders’ voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their direct transferees and their indirect transferees approved by our general partner (which approval may be granted in its sole discretion) and persons who acquired such units with the prior approval of our general partner, cannot vote on any matter.

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of USA Compression Holdings to transfer all or a portion of its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers.

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An increase in interest rates may cause the market price of our common units to decline.

Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield based equity investments such as publicly traded partnership interests. Reduced demand for our common units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.

We may issue additional units without your approval, which would dilute your existing ownership interests.

Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units, including pursuant to our Dividend Reinvestment Plan (“DRIP”), or other equity securities of equal or senior rank, will have the following effects:

· our existing unitholders’ proportionate ownership interest in us will decrease;

· the amount of cash available for distribution on each unit may decrease;

· because a lower percentage of total outstanding units will be subordinated units during the subordination period, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

· the ratio of taxable income to distributions may increase;

· the relative voting strength of each previously outstanding unit may be diminished; and

· the market price of the common units may decline.

USA Compression Holdings may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

USA Compression Holdings holds an aggregate of 4,048,588 common units and 14,048,588 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and may convert earlier under certain circumstances. In addition, USA Compression Holdings may acquire additional common units in connection with our planned DRIP. We have agreed to provide USA Compression Holdings with certain registration rights for any common and subordinated units it owns. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

Our general partner has a call right that may require you to sell your units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result, you may be required to sell your common units at an undesirable time or price. You may also incur a tax liability upon a sale of your units. USA Compression Holdings owns an aggregate of approximately 26.9% of our outstanding common units. At the end of the subordination period (which could occur as early as December 31, 2013), assuming no additional issuances of common units (other than upon the conversion of the subordinated units), USA Compression Holdings will own an aggregate of approximately 62.2% of our outstanding common units.

Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner

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interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:

· we were conducting business in a state but had not complied with that particular state’s partnership statute; or

· your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, or the Delaware Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.

The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

Our common units are listed on the NYSE. Because we are a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders do not have the same protections afforded to investors in certain corporations that are subject to all of the NYSE corporate governance requirements. Please read Part III, Item 10 (“Directors, Executive Officers and Corporate Governance”).

Pursuant to recently enacted federal securities laws, our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404 of the Sarbanes Oxley Act of 2002 for so long as we are an emerging growth company.

We are required to disclose changes made in our internal control over financial reporting on a quarterly basis, and we will be required to assess the effectiveness of our controls annually. However, for as long as we are an “emerging growth company” under federal securities laws, our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404. We could be an emerging growth company for up to five years. Even if we conclude that our internal control over financial reporting is effective, our independent registered public accounting firm may still decline to attest to our assessment or may issue a report that is qualified if it is not satisfied with our controls or the level at which our controls are documented, designed, operated or reviewed, or if it interprets the relevant requirements differently from us.

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, which would subject us to entity level taxation, then our cash available for distribution to our unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we are or will be so treated, a change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

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If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes, there would be a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

If we were subjected to a material amount of additional entity level taxation by individual states, it would reduce our cash available for distribution to our unitholders.

Changes in current state law may subject us to additional entity level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay Texas franchise tax each year at a maximum effective rate of 0.7% of our gross income apportioned to Texas in the prior year. Imposition of any similar taxes by any other state may substantially reduce the cash available for distribution to our unitholders and, therefore, negatively impact the value of an investment in our common units. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to additional amounts of entity level taxation, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, judicial interpretations of the U.S. federal income tax laws may have a direct or indirect impact on our status as a partnership and, in some instances, a court’s conclusions may heighten the risk of a challenge regarding our status as a partnership. Moreover, from time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that would affect the tax treatment of certain publicly traded partnerships. One such recent legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations, upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes or differing judicial interpretations of existing laws could be applied retroactively and could negatively impact the value of an investment in our common units.

Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

Our unitholders’ share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.

Because a unitholder will be treated as a partner to whom we will allocate taxable income that could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income will be taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes, on its share of our taxable income even if it receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this report or from the positions we take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a

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materially adverse impact on the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If our unitholders sell common units, they will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if it sells such common units at a price greater than its tax basis in those common units, even if the price received is less than its original cost. Furthermore, a substantial portion of the amount realized on any sale of common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult a tax advisor before investing in our common units.

We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. Our counsel is unable to opine as to the validity of such filing positions. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.

We prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We will prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. The U.S. Treasury Department’s proposed Treasury Regulations allowing a similar monthly simplifying convention are not final and do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to effect a short sale of common units) may be considered as having disposed of those common units. If so, he would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered as having disposed of the loaned common units, he may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.

We will adopt certain valuation methodologies and monthly conventions for federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

The sale or exchange of 50% or more of our capital and profits interests during any twelve month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have technically terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A technical termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for such tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has recently announced a publicly traded partnership technical termination relief program whereby a publicly traded partnership that technically terminated may request publicly traded partnership technical termination relief which, if granted by the IRS, among other things would permit the partnership to provide only one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years.

As a result of investing in our common units, you will likely become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we

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conduct business or control property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently conduct business in thirteen states. Many of these states currently impose a personal income tax on individuals. Many of these states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may control assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. It is your responsibility to file all foreign, federal, state and local tax returns.

ITEM 1B. Unresolved Staff Comments

None.

ITEM 2. Properties

ITEM 3. Legal Proceedings

None.

ITEM 4. Mine Safety Disclosures

None.

PART II

ITEM 5. Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our Partnership Interests

As of March 22, 2013, we had outstanding 15,048,588 common units, 14,048,588 subordinated units, a 2% general partner interest and incentive distribution rights, or IDRs. As of March 22, 2013, USA Compression Holdings, LLC owned approximately 26.9% of our outstanding common units and 100% of our subordinated units. Our general partner currently owns a 2.0% general partner interest in us and all of our IDRs. As discussed below under “Selected Information from Our Partnership Agreement— General Partner Interest and IDRs,” the IDRs represent the right to receive increasing percentages, up to a maximum of 48%, of the cash we distribute from operating surplus (as defined below) in excess of $0.4888 per unit per quarter. Our common units, which represent limited partner interests in us, are listed on the New York Stock Exchange (“NYSE”) under the symbol “USAC.” Our common units have been traded on the NYSE since January 15, 2013, and therefore, we have not set forth quarterly information with respect to the high and low prices for our common units. On March 22, 2013, the closing price of a common unit was $19.20.

Holders

At the close of business on March 22, 2013, we had 7 holders of record of our common units. The number of record holders does not include holders of shares in “street names” or persons, partnerships, associations, corporations or other entities identified in security position listings maintained by depositories.

Selected Information from our Partnership Agreement

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions, minimum quarterly distributions and IDRs.

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Available Cash

Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending March 31, 2013, we distribute all of our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date. Our partnership agreement generally defines available cash, for each quarter, as cash on hand at the end of a quarter less the amount of reserves established by our general partner to provide for the proper conduct of our business, comply with applicable law, our revolving credit facility or other agreements; and provide fund for distributions to our unitholders for any one or more of the next four quarters plus cash on hand resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are borrowings made under a credit facility, commercial paper facility or other similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within twelve months from sources other than working capital borrowings.

Minimum Quarterly Distribution

Our partnership agreement provides that, during the subordination period, the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.425 per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units. We expect that we will pay a prorated distribution for the quarter ending March 31, 2013, the quarter in which we became a publicly-traded company. This distribution will cover the period from January 18, 2013, the closing date of the IPO, to and including March 31, 2013. We expect to pay this cash distribution on or before May 15, 2013.

General Partner Interest and IDRs

Our partnership agreement provides that our general partner initially will be entitled to 2.0% of all distributions that we make. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest if we issue additional units. Our general partner’s 2.0% interest, and the percentage of our cash distributions to which it is entitled, will be proportionately reduced if we issue additional units in the future (other than the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units upon a reset of the incentive distribution rights) and our general partner does not contribute a proportionate amount of capital to us in order to maintain its 2.0% general partner interest. Our partnership agreement does not require that the general partner fund its capital contribution with cash and our general partner may fund its capital contribution by the contribution to us of common units or other property.

Incentive distribution rights represent the right to receive increasing percentages (13.0%, 23.0% and 48.0%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest.

Issuer Purchases of Equity Securities

None.

Sales of Unregistered Securities; Use of Proceeds from Sale of Securities

On January 18, 2013, we completed our IPO of common units pursuant to a Registration Statement on Form S-1, as amended (Reg. No. 333-174803), that was declared effective on January 14, 2013. Under the registration statement, we sold an aggregate of 11,000,000 common units at a price to the public of $18.00 per common unit. Barclays Capital Inc. and Goldman, Sachs & Co. acted as joint book-running managers of the offering. The offering closed on January 18, 2013. As a result of our IPO, we raised a total of $198.0 million in gross proceeds, and approximately $180.8 million in net proceeds after deducting underwriting discounts and commissions of $12.2 million, structuring fees of $0.7 million and offering expenses of $4.3 million.

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ITEM 6. Selected Financial Data

SELECTED HISTORICAL FINANCIAL DATA

In the table below we have presented certain selected financial data for USA Compression Partners, LP for each of the five years in the period ended December 31, 2012, which has been derived from our audited consolidated financial statements. The following information should be read together with Management’s Discussion and Analysis of Financial Condition and Results of Operations and the Financial Statements contained in Item 7 of this report.

We were acquired by USA Compression Holdings on December 23, 2010, which we refer to as the Holdings Acquisition. In connection with this acquisition, our assets and liabilities were adjusted to fair value on the closing date by application of “push-down” accounting. Due to these adjustments, our audited condensed consolidated financial statements are presented in two distinct periods to indicate the application of two different bases of accounting between the periods presented: (i) the periods prior to the acquisition date for accounting purposes, using a date of convenience of December 31, 2010, are identified as “Predecessor,” and (ii) the periods from December 31, 2010 forward are identified as “Successor.” Please read note 1 to our audited financial statements as of December 31, 2012 included elsewhere in this report.

The following table includes the non-GAAP financial measure of Adjusted EBITDA. We define Adjusted EBITDA as our net income before interest expense, income taxes, depreciation expense, impairment of compression equipment, share based compensation expense, restructuring charges, management fees, expenses under our operating lease with Caterpillar and certain fees and expenses related to the Holdings Acquisition. For a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please read “—Non-GAAP Financial Measures.”

	Successor(1)							Predecessor
	Years Ended December 31,							Years Ended December 31,
	2012				2011			2010			2009			2008
	(in thousands)							(in thousands)
Revenues:
Contract operations	$	116,373		$		93,896		$	89,785		$	93,178		$	87,905
Parts and service	2,414			4,824				2,243			2,050			2,918
Total revenues	118,787			98,720				92,028			95,228			90,823
Costs and expenses:
Cost of operations	37,796			39,605				33,292			30,096			29,320
Selling, general and administrative	18,269			12,726				11,370			9,136			8,709
Restructuring charges(2)	—			300				—			—			—
Depreciation and amortization	41,880			32,738				24,569			22,957			18,016
(Gain) loss of sale of assets	266			178				(90		)	(74		)	(235		)
Impairment of compression equipment	—			—				—			1,677			—
Total costs and expenses	98,211			85,547				69,141			63,792			55,810
Operating income	20,576			13,173				22,887			31,436			35,013
Other income (expense):
Interest expense	(15,905		)	(12,970			)	(12,279		)	(10,043		)	(14,003		)
Other	28			21				26			25			20
Total other expense	(15,877		)	(12,949			)	(12,253		)	(10,018		)	(13,983		)
Income before income tax expense	4,699			224				10,634			21,418			21,030
Income tax expense(3)	196			155				155			190			119
Net income	$	4,503		$		69		$	10,479		$	21,228		$	20,911
Adjusted EBITDA	$	63,484		$		51,285		$	51,987		$	56,917		$	53,274

Other Financial Data:
Capital expenditures(4)	$	179,977		$		133,264		$	18,886		$	29,580		$	92,708
Cash flows provided by (used in):
Operating activities	41,974			33,782				38,572			42,945			40,699
Investing activities	(178,589		)	(140,444			)	(18,768		)	(26,763		)	(88,102		)
Financing activities	136,618			106,662				(19,804		)	(16,545		)	46,364

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	Successor (1)									Predecessor
	December 31,									December 31,
	2012			2011			2010			2009			2008
	(in thousands)									(in thousands)
Balance Sheet Data (at period end):
Working capital(5)	$	(12,076	)	$	(11,295	)	$	(3,984	)	$	(4,678	)	$	(7,656	)
Total assets	872,645			727,876			614,718			352,757			349,645
Long-term debt	502,266			363,773			255,491			260,470			276,537
Partners’ equity	343,526			339,023			338,954			72,626			49,685

(1) Reflects the push-down of the purchase accounting for the Holdings Acquisition.

(2) During the year ended December 31, 2011, we incurred $0.3 million of restructuring charges for severance and retention benefits related to the termination of certain administrative employees. These charges are reflected as restructuring charges in our consolidated statement of operations. These restructuring charges were paid in 2012.

(3) This represents the Texas franchise tax (applicable to income apportioned to Texas) which, in accordance with Financial Accounting Standards Board Accounting Standards Codification 740 “Income Taxes,” or ASC 740, is classified as income tax for reporting purposes.

(4) On December 15, 2011, we purchased all the compression units previously leased from Caterpillar for $43 million and terminated all the lease schedules and covenants under the facility. This amount is included in capital expenditures for the year ended December 31, 2011. On December 16, 2011, the Partnership entered into an agreement with a compression equipment supplier to reduce certain previously made progress payments from $10 million to $2 million. The Partnership applied this $8 million credit to new compression unit purchases from this supplier in the year ended December 31, 2012. Before the application of this credit, capital expenditures were $188.0 million for the year ended December 31, 2012.

(5) Working capital is defined as current assets minus current liabilities.

Non-GAAP Financial Measures

We define Adjusted EBITDA as our net income before interest expense, income taxes, depreciation expense, impairment of compression equipment, share based compensation expense, restructuring charges, management fees, expenses under our operating lease with Caterpillar and certain fees and expenses related to the Holdings Acquisition. We view Adjusted EBITDA as one of our primary management tools, and we track this item on a monthly basis both as an absolute amount and as a percentage of revenue compared to the prior month, year-to-date and prior year and to budget. Adjusted EBITDA is used as a supplemental financial measure by our management and external users of our financial statements, such as investors and commercial banks, to assess:

· the financial performance of our assets without regard to the impact of financing methods, capital structure or historical cost basis of our assets;

· the viability of capital expenditure projects and the overall rates of return on alternative investment opportunities;

· the ability of our assets to generate cash sufficient to make debt payments and to make distributions; and

· our operating performance as compared to those of other companies in our industry without regard to the impact of financing methods and capital structure.

We believe that Adjusted EBITDA provides useful information to investors because, when viewed with our GAAP results and the accompanying reconciliations, it provides a more complete understanding of our performance than GAAP results alone. We also believe that external users of our financial statements benefit from having access to the same financial measures that management uses in evaluating the results of our business.

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP as measures of operating performance and liquidity. Moreover, our Adjusted EBITDA as presented may not be comparable to similarly titled measures of other companies.

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Adjusted EBITDA does not include interest expense, income taxes, depreciation expense, impairment of compression equipment, share based compensation expense, restructuring charges, management fees, expenses under our operating lease with Caterpillar and certain fees and expenses related to the Holdings Acquisition. Because we borrow money under our revolving credit facility and have historically utilized operating leases to finance our operations, interest expense and operating lease expense are necessary elements of our costs. Because we use capital assets, depreciation and impairment of compression equipment is also a necessary element of our costs. Expense related to share based compensation expense related to equity awards to employees is also necessary to operate our business. Therefore, measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net income and net cash provided by operating activities determined under GAAP, as well as Adjusted EBITDA, to evaluate our financial performance and our liquidity. Our Adjusted EBITDA excludes some, but not all, items that affect net income and net cash provided by operating activities, and these measures may vary among companies. Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating this knowledge into management’s decision making processes.

The following table reconciles Adjusted EBITDA to net income and net cash provided by operating activities, its most directly comparable GAAP financial measures, for each of the periods presented:

	Successor						Predecessor
	Years Ended December 31,						Years Ended December 31,
	2012			2011			2010			2009			2008
	(in thousands)						(in thousands)
Net income	$	4,503		$	69		$	10,479		$	21,228		$	20,911
Interest expense	15,905			12,970			12,279			10,043			14,003
Depreciation and amortization	41,880			32,738			24,569			22,957			18,016
Income taxes	196			155			155			190			119
Impairment of compression equipment(1)	—			—			—			1,677			—
Share based compensation expense	—			—			382			269			225
Equipment operating lease expense(2)	—			4,053			2,285			553			—
Riverstone management fee(3)	1,000			1,000			—			—			—
Restructuring charges(4)	—			300			—			—			—
Fees and expenses related to the Holdings Acquisition(5)	—			—			1,838			—			—
Adjusted EBITDA	$	63,484		$	51,285		$	51,987		$	56,917		$	53,274
Interest expense	(15,905		)	(12,970		)	(12,279		)	(10,043		)	(14,003		)
Income tax expense	(196		)	(155		)	(155		)	(190		)	(119		)
Equipment operating lease expense	—			(4,053		)	(2,285		)	(553		)	—
Riverstone management fee	(1,000		)	(1,000		)	—			—			—
Restructuring charge	—			(300		)	—			—			—
Fees and expenses related to the Holdings Acquisition	—			—			(1,838		)	—			—
Other	(58		)	(920		)	3,362			288			201
Changes in operating assets and liabilities:
Accounts receivable and advance to employee	169			(976		)	(336		)	1,865			(2,458		)
Inventory	(1,004		)	1,974			503			(3,680		)	(155		)
Prepaids	(153		)	(219		)	(18		)	608			(1,165		)
Other non-current assets	(1,315		)	(2,601		)	1			(4		)	(3		)
Accounts payable	(5,340		)	1,987			(825		)	(857		)	1,960
Accrued liabilities and deferred revenue	3,292			1,730			455			(1,406		)	3,167
Net cash provided by operating activities	$	41,974		$	33,782		$	38,572		$	42,945		$	40,699

(1) Represents non-cash charges incurred to write down long-lived assets with recorded values that are not expected to be recovered through future cash flows.

(2) Represents expenses for the respective periods under the operating lease facility with Caterpillar, from whom we historically leased compression units and other equipment. On December 15, 2011, we purchased the compression units that were previously leased from Caterpillar for $43 million and terminated all the lease schedules and covenants under the facility. As such, we believe it is useful to investors to view our results excluding these lease payments.

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(3) Represents management fees paid to Riverstone for services performed during 2012 and 2011. As these fees will not be paid by us as a public company, we believe it is useful to investors to view our results excluding these fees.

(4) During the year ended December 31, 2011, we incurred $0.3 million of restructuring charges for severance and retention benefits related to the termination of certain administrative employees. These charges are reflected as restructuring charges in our consolidated statement of operations. These restructuring charges were paid in 2012. We believe that it is useful to investors to view our results excluding this non-core expense.

(5) Represents one-time fees and expenses related to the Holdings Acquisition. These fees and expenses are not related to our operations, and we do not expect to incur similar fees or expenses in the future as a publicly traded partnership.

We define distributable cash flow as net income (loss) plus non-cash interest expense, depreciation and amortization expense, impairment of compression equipment charges, and non-cash SG&A costs, less maintenance capital expenditures. We believe distributable cash flow is an important measure of operating performance because it allows management, investors and others to compare basic cash flows we generate (prior to the establishment of any retained cash reserves by our general partner) to the cash distributions we expect to pay our unitholders. Using distributable cash flow, management can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Our distributable cash flow may not be comparable to a similarly titled measure of another company because other entities may not calculate distributable cash flow in the same manner.

Distributable cash flow is not a measure of financial performance under GAAP, and should not be considered in isolation or as an alternative to net income (loss), cash flows from operating activities and other measures determined in accordance with GAAP. Items excluded from distributable cash flow are significant and necessary components to the operations of our business, and, therefore, distributable cash flow should only be used as a supplemental measure of our operating performance.

The following table reconciles our net income to distributable cash flow for each of the periods presented:

	Successor					Predecessor
	Years Ended December 31,					Years Ended December 31,
	2012		2011			2010		2009		2008
	(in thousands)					(in thousands)
Net income	$	4,503	$	69		$	10,479	$	21,228	$	20,911
Plus: Non-cash interest expense	1,855		(1,057		)	3,449		363		361
Plus: Depreciation and amortization	41,880		32,738			24,569		22,957		18,016
Plus: Impairment of compression equipment	—		—			—		1,677		—
Plus: Share based compensation expense	—		—			382		269		225
Less: Maintenance capital expenditures(1)	13,310		8,961			13,018		9,354		7,106
Distributable cash flow	$	34,928	$	22,789		$	25,861	$	37,140	$	32,407

(1) Reflects actual maintenance capital expenditures for the period presented. Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets, to maintain the operating capacity of our assets and extend their useful lives, or other capital expenditures that are incurred in maintaining our existing business and related cash flow.

ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements, the notes thereto, and the other financial information appearing elsewhere in this report. The following discussion includes forward-looking statements that involve certain risks and uncertainties. See Part I (“Disclosure Regarding Forward-Looking Statements”) and Part I, Item 1A (“Risk Factors”) in this report.

Overview

We are a growth oriented Delaware limited partnership and, based on management’s significant experience in the industry, we believe that we are one of the largest independent providers of compression services in the U.S. in terms of total compression unit horsepower. We have been providing compression services since 1998. We currently operate in a number of U.S. natural gas shale plays, including the Fayetteville, Marcellus, Woodford, Barnett, Eagle Ford and Haynesville shales. We believe compression services for shale production will increase in the future. According to the Annual Energy Outlook 2013 Early Release prepared by the EIA, natural gas production from shale formations will increase from 34% of total U.S. natural gas production in 2011 to 50% of total U.S.

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natural gas production in 2040. We also provide compression services in more mature conventional basins that will require increasing amounts of compression as they age and pressures decline.

We operate in a single business segment, the compression service business. We provide our customers with compression services to maximize their natural gas and crude oil production, throughput and cash flow. We provide domestic compression services to major oil companies and independent producers, processors, gatherers and transporters of natural gas using our modern, flexible fleet of compression units, which have been designed to be rapidly deployed and redeployed throughout the country. As part of our services, we engineer, design, operate, service and repair our compression units and maintain related support inventory and equipment.

We provide our compression services primarily under long-term, fixed fee contracts. Our contracts have initial contract terms of up to five years. Our customers generally require compression services at their locations for longer than the initial contract term. We typically continue to provide compression services to our customers beyond their initial contract terms, either through renewals or on a month-to-month basis. As of and for the year ended December 31, 2012, approximately 35% of our compression services on a horsepower basis (and 38% on a revenue basis) were provided to customers under contracts continuing on a month to month basis. Our customers are typically required to pay our monthly fee even during periods of limited or disrupted natural gas flows, which enhances the stability and predictability of our cash flows. We are not directly exposed to natural gas price risk because we do not take title to the natural gas we compress and because the natural gas used as fuel for our compression units is supplied by our customers without cost to us. Our indirect exposure to short-term volatility in natural gas and crude oil commodity prices is mitigated by the long-term nature of the majority of our contracts. As of December 31, 2012, we estimate that approximately 90% of our revenue generating horsepower was deployed in large volume gathering systems, processing facilities and transportation applications.

General Trends and Outlook

From 2006 through 2008, the compression industry in the U.S. experienced a period of significant strength. Our average annual horsepower utilization rates ranged from 94% to 97% during these years, and our average revenue per revenue generating horsepower per month increased from $14.18 in 2006 to $16.24 in 2008. During 2009 and the first half of 2010, the industry experienced pricing pressure as a result of reduced commodity prices and energy activity, an excess supply of gas compression equipment in the industry and the rationalization of compression equipment by producers, processors, gatherers and transporters of natural gas that has included replacing outsourced compression services with customer owned equipment and downsizing compression units. Average monthly revenue per revenue generating horsepower declined to $16.05 in 2009, $14.70 in 2010 and $14.07 in 2011, although our utilization rates averaged 93% for 2009 and 2010 and 92% for 2011. Pricing for the compression industry in the U.S. began to stabilize in mid-2010 and improved slightly during the second half of 2010 and remained stable in 2011.

Our average monthly revenue per revenue generating horsepower continued to decline slightly through 2012, as market rates in 2009 and early 2010 were lower than market rates prior to 2009, and as older contracts at higher rates expire, a larger percentage of our contracts were at the lower rates prevalent since 2009. During 2009 and early 2010, we elected to sign shorter term contracts wherever practical to limit our long-term exposure to the lower rates prevalent at the time. Rates improved in the second half of 2010 and remained relatively stable through 2011. While market rates generally improved during 2012, we experienced pricing pressure across the horsepower ranges of our fleet (other than our largest horsepower units), and we expect to continue to experience pricing pressure through 2013. However, over the long term, we expect that continued improved pricing will ultimately improve our average monthly revenue per revenue generating horsepower as contracts that we entered into in 2009 and early 2010 expire and we enter into new contracts at higher rates. We intend to grow the number of large horsepower units in our fleet. While large horsepower units in general allow us to generate higher gross operating margins than lower horsepower units, they also generate lower average monthly revenue per revenue generating horsepower.

Our ability to increase our revenues is dependent in large part on our ability to add new revenue generating compression units to our fleet and increase the utilization of idle compression units. During 2010, we began to see an increase in overall natural gas activity in the U.S. and experienced an increase in demand for our compression services. Revenue generating horsepower increased by 22.3% from December 31, 2011 to December 31, 2012. The average revenue generating horsepower increased by 31.3% from the year ended December 31, 2011 to the year ended December 31, 2012. We believe the activity levels in the U.S. will continue to increase, particularly in shale plays. We anticipate this activity will result in higher demand for our compression services, which we believe should result in increasing revenues. However, the expected increase in overall natural gas activity and demand for our compression services may not occur for a variety of reasons. See Part I (“Disclosure Regarding Forward-Looking Statements”).

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Factors That Affect Our Future Results

Customers

We provide compression services to major oil companies and independent producers, processors, gatherers and transporters of natural gas, and operate in a number of U.S. natural gas shale plays, including the Fayetteville, Marcellus, Woodford, Barnett, Eagle Ford and Haynesville shales. Our customers use our services primarily in large volume gathering systems, processing facilities and transportation applications. Regardless of the application for which our services are provided, our customers rely upon the availability of the equipment used to provide compression services and our expertise to help generate the maximum throughput of product, reduce fuel costs and reduce emissions. While we are currently focused on our existing service areas, our customers have natural gas compression demands in other areas of the U.S. in conjunction with their field development projects. We continually consider expansion of our areas of operation in the U.S. based upon the level of customer demand. Our modern, flexible fleet of compression units, which have been designed to be rapidly deployed and redeployed throughout the country, provides us with continuing opportunities to expand into other areas with both new and existing customers. From April 2008 through December 2012, we redeployed approximately 57,400 horsepower of our compression units from our Central operating region to our Northeast operating region, which includes the Marcellus shale, to meet increasing customer demand in that geographic area. Many of our customers have access to low-cost capital made available by banks and equipment manufacturers and have elected to access this capital to add compression units to their owned compression fleets. Additional purchases of compression equipment by our customers may result in reduced demand for our compression services by these customers, which could materially reduce our results of operations and ability to make cash distributions to our unitholders.

Supply and Demand for Natural Gas

We believe that as a clean alternative to other fuels, natural gas will continue to be a fuel of choice for many years to come for many industries and consumers. The EIA forecasts in its Annual Energy Outlook 2013 Early Release that natural gas consumption in the U.S. will increase by approximately 21% from 2011 to 2040. We believe this long-term increasing demand for natural gas will create increasing demand for compression services, for both natural gas fields as they age and for the development of new natural gas fields. Additionally, the shift to production of natural gas from shale, tight gas and coal bed formations that often have lower producing pressures than conventional reservoirs, results in a further increase in compression needs. In the short-term, changes in natural gas pricing, based primarily upon the supply of natural gas, will affect the development activities of natural gas producers based upon the costs associated with finding and producing natural gas in the particular natural gas and oil fields in which they are active. Although short-term declines in natural gas prices have a short-term negative effect on the development activity in natural gas fields, periods of lower development activity tend to place emphasis on improving production efficiency. As a result of our commitment to providing a high level of availability of the equipment used to provide compression services, we believe our service run times position us to satisfy the needs of our customers.

Access to External Expansion Capital

In determining the amount of cash available for distribution, the board of directors of our general partner will determine the amount of cash reserves to set aside for our operations, including reserves for future working capital, maintenance capital expenditures, expansion capital expenditures and other matters, which will impact the amount of cash we are able to distribute to our unitholders. However, we expect that we will rely primarily upon external financing sources, including borrowings under our revolving credit facility and issuances of debt and equity securities, rather than cash reserves, to fund our expansion capital expenditures. To the extent we are unable to finance growth externally and are unwilling to establish cash reserves to fund future expansions, our cash available for distribution will not significantly increase. In addition, because we distribute all of our available cash, we may not grow as quickly as businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or in the terms of our revolving credit facility on our ability to issue additional units, including units ranking senior to the common units.

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Operating Highlights

The following table summarizes certain horsepower and horsepower utilization percentages for the periods presented.

	Successor								Predecessor
	Year Ended December 31,				Percent Change				Year Ended December 31,				Percent Change
Operating Data (unaudited):	2012		2011		2012		2011		2010		2009		2010
Fleet horsepower(1)	919,121		722,201		27.3	%	18.4	%	609,730		582,530		4.7	%
Total available horsepower(2)	935,681		809,418		15.6	%	32.2	%	612,410		582,530		5.1	%
Revenue generating horsepower(3)	794,324		649,285		22.3	%	21.7	%	533,692		502,177		6.3	%
Average revenue generating horsepower(4)	749,821		570,900		31.3	%	10.5	%	516,703		489,243		5.6	%
Revenue generating compression units	978		888		10.1	%	11.7	%	795		749		6.1	%
Average horsepower per revenue generating compression unit(5)	791		692		14.3	%	3.7	%	667		655		1.8	%
Horsepower utilization(6):
At period end	92.8	%	95.7	%	(3.0	)%	4.2	%	91.8	%	92.0	%	(0.2	)%
Average for the period(7)	94.5	%	92.3	%	2.4	%	(0.3	)%	92.6	%	92.7	%	(0.1	)%

(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 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 a 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 horsepower per revenue generating horsepower for each of the months in the period.

(5) Calculated as the average of the month-end horsepower per revenue generating compression unit for each of the months in the period.

(6) Horsepower utilization is calculated as (i)(a) revenue generating horsepower plus (b) horsepower in our fleet that is under contract, but is not yet generating revenue plus (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 at each applicable period end was 86.4%, 89.9%, 87.5% and 86.2%, for the years ended December 31, 2012, 2011, 2010 and 2009 respectively.

(7) Calculated as the average utilization for the months in the period based on utilization at the end of each month in the period.

The increase in fleet horsepower as of December 31, 2012 compared to December 31, 2011 is attributable to the compression units added to our fleet to meet the incremental demand by new and current customers. Revenue generating horsepower increased by 22.3% from December 31, 2011 to December 31, 2012. The average horsepower per revenue generating compression unit increased from 692 to 791, or 14.3%, over that same period. The increase in fleet horsepower as of December 31, 2011 compared to December 31, 2010 is attributable to the compression units added to our fleet to meet the incremental demand by new and current customers. Revenue generating horsepower increased by 21.7% from December 31, 2010 to December 31, 2011. The average horsepower per revenue generating compression unit increased from 667 to 692 between 2010 and 2011.

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	Successor										Predecessor
	Year Ended December 31,						Percent Change				Year Ended December 31,						Percent Change
Other Financial Data:	2012			2011			2012		2011		2010			2009			2010
	(dollars in thousands)										(dollars in thousands)
Gross Operating Margin(1)	$	80,991		$	59,115		37.0	%	0.6	%	$	58,736		$	65,132		(9.8	)%
Adjusted EBITDA(2)	$	63,484		$	51,285		23.8	%	(1.4	)%	$	51,987		$	56,917		(8.7	)%
Gross operating margin percentage(3)	68.2		%	59.9		%	13.9	%	(6.1	)%	63.8		%	68.4		%	(6.7	)%
Adjusted EBITDA percentage(3)	53.4		%	51.9		%	2.9	%	(8.1	)%	56.5		%	59.8		%	(5.5	)%

(1) Gross operating margin is a non-GAAP financial measure. We calculate gross operating margin as revenue less cost of operations, exclusive of depreciation and amortization expense. We believe that gross operating margin is useful as a supplemental measure of our operating profitability. Gross operating margin should not be considered an alternative to, or more meaningful than, operating income or any other measure of financial performance presented in accordance with GAAP. Moreover, gross operating margin as presented may not be comparable to similarly titled measures of other companies. Because we capitalize assets, depreciation and amortization of equipment is a necessary element of our costs. To compensate for the limitations of gross operating margin as a measure of our performance, we believe that it is important to consider operating income determined under GAAP, as well as gross operating margin, to evaluate our operating profitability.

The following table reconciles gross operating margin to operating income, its most directly comparable GAAP financial measure, for each of the periods presented:

	Successor				Predecessor
	Year Ended December 31,				Year Ended December 31
	2012		2011		2010			2009
	(in thousands)				(in thousands)
Revenues:
Contract operations	$	116,373	$	93,896	$	89,785		$	93,178
Parts and service	2,414		4,824		2,243			2,050
Total revenues	118,787		98,720		92,028			95,228
Cost of operations, exclusive of depreciation and amortization	37,796		39,605		33,292			30,096
Gross operating margin	80,991		59,115		58,736			65,132
Other operating and administrative costs and expenses:
Selling, general and administrative	18,269		12,726		11,370			9,136
Restructuring charges	¾		300		¾			¾
Depreciation and amortization	41,880		32,738		24,569			22,957
(Gain) loss on sale of assets	266		178		(90		)	(74		)
Impairment of compression equipment	¾		¾		¾			1,677
Total other operating and administrative costs and expenses	60,415		45,942		35,849			33,696
Operating income	$	20,576	$	13,173	$	22,887		$	31,436

(2) For a reconciliation of Adjusted EBITDA, a non-GAAP financial measure, to net income and cash flows from operating activities, its most directly comparable GAAP financial measures, see “Selected Historical and Pro Forma Financial and Operating Data—Non-GAAP Financial Measures.”

(3) Gross operating margin percentage and Adjusted EBITDA percentage are calculated as a percentage of revenue.

Gross operating margin, as a percentage of total revenues, increased to 68.2% in 2012 from 59.9% in 2011. The increase in gross operating margin was primarily attributable to a 20.3% increase in total revenues when comparing the periods, and a 4.6% decrease in cost of operations. Average revenue generating horsepower increased from 570,900 in 2011 to 749,821 in 2012, an increase of 31.3%. Average revenue per revenue generating horsepower per month declined to $13.39 in 2012 from $14.07 in 2011, a

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Financial Results of Operations

Year ended December 31, 2012 compared to the year ended December 31, 2011

The following table summarizes our results of operations for the periods presented:

	Successor
	Year Ended December 31,						Percent
	2012			2011			Change
	(in thousands)
Revenues:
Contract operations	$	116,373		$	93,896		23.9	%
Parts and service	2,414			4,824			(50.0	)%
Total revenues	118,787			98,720			20.3	%
Costs and expenses:
Cost of operations, exclusive of depreciation and amortization	37,796			39,605			(4.6	)%
Selling, general and administrative	18,269			12,726			43.6	%
Restructuring charges	—			300
Depreciation and amortization	41,880			32,738			27.9	%
(Gain) loss on sale of assets	266			178			49.4	%
Total costs and expenses	98,211			85,547			14.8	%
Operating income	20,576			13,173			56.2	%
Other income (expense):
Interest expense	(15,905		)	(12,970		)	22.6	%
Other	28			21			33.3	%
Total other expense	(15,877		)	(12,949		)	22.6	%
Income before income tax expense	4,699			224			1,997.8	%
Income tax expense	196			155			26.5	%
Net income	$	4,503		$	69		6,426.1	%

Contract operations revenue. Contract operations revenue was $116.4 million for the year ended December 31, 2012 compared to $93.9 million in 2011, an increase of 23.9%. Average revenue generating horsepower increased from 570,900 for the year ended December 31, 2011 to 749,821 for the year ended December 31, 2012, an increase of 31.3%. Average revenue per revenue generating horsepower per month declined from $14.07 for the year ended December 31, 2011 to $13.39 for the year ended December 31, 2012, a decrease of 4.8%. The decline in average revenue per revenue generating horsepower per month related primarily to the 14.3% increase in the estimated average horsepower per revenue generating compression unit, which was 692 and 791 at December 31, 2011 and 2012, respectively, as large horsepower compression units generally generate lower average monthly revenue per revenue generating horsepower. While pricing for these services stabilized in mid-2010 and 2011 and began to improve during 2012, compression units that were placed under service contracts during 2009 and 2010 were contracted at lower market rates. There were 978 revenue generating compression units at December 31, 2012 compared to 888 at December 31, 2011, a 10.1% increase. Revenue generating horsepower was 794,324 at December 31, 2012 compared to 649,285 at December 31, 2011, a 22.3% increase.

Parts and service revenue. Parts and service revenue was $2.4 million for the year ended December 31, 2012 compared to $4.8 million in 2011, or a 50.0% decrease. A portion of retail service revenue, including billings for trucking and crane services, was $1.1 million during 2011, including $1.0 million recognized during the fourth quarter of 2011 due to the deployment and redeployment of compression units. These ancillary trucking and crane services, all of which are billed to customers, result in no gross operating margin.

Cost of operations, exclusive of depreciation and amortization. Cost of operations was $37.8 million for the year ended December 31, 2012 compared to $39.6 million for the year ended December 31, 2011, a decrease of 4.6%. The decrease is attributable to a $4.1 million decrease in equipment operating lease expense, as the Caterpillar operating lease schedules were terminated on December 15, 2011. Partially offsetting the decrease related to the Caterpillar operating lease are certain cost increases consisting of (1) a $1.1 million increase in lubrication oil expenses due to both a 7.1% increase in the average supplier price per gallon and a 12.7% increase in gallons consumed, (2) a $1.0 million increase in direct labor expenses and (3) a $0.3 million increase related to vehicle tools and gasoline, all of which were attributable primarily to the increase in the size of our fleet. The cost of operations was 31.8% of revenue for the year ended December 31, 2012 as compared to 40.2% for the year ended December 31, 2011.

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Year ended December 31, 2011 compared to the year ended December 31, 2010

The following table summarizes our results of operations for the periods presented:

	Successor			Predecessor
	Year Ended December 31,			Year Ended December 31,			Percent
	2011			2010			Change
	(in thousands)			(in thousands)
Revenues:
Contract operations	$	93,896		$	89,785		4.6	%
Parts and service	4,824			2,243			115.1	%
Total revenues	98,720			92,028			7.3	%
Costs and expenses:
Cost of operations, exclusive of depreciation and amortization	39,605			33,292			19.0	%
Selling, general and administrative	12,726			11,370			11.9	%
Restructuring charges	300			—
Depreciation and amortization	32,738			24,569			33.2	%
(Gain) loss on sale of assets	178			(90		)	(297.8	)%
Total costs and expenses	85,547			69,141			23.7	%
Operating income	13,173			22,887			(42.4	)%
Other income (expense):
Interest expense	(12,970		)	(12,279		)	5.6	%
Other	21			26			(19.2	)%
Total other expense	(12,949		)	(12,253		)	5.7	%
Income before income tax expense	224			10,634			(97.9	)%
Income tax expense	155			155			0.0	%
Net income	$	69		$	10,479		(99.3	)%

Contract operations revenue. Contract operations revenue was $93.9 million for the year ended December 31, 2011 compared to $89.8 million in 2010, an increase of 4.6%. Average revenue generating horsepower increased from 516,703 for the year ended December 31, 2010 to 570,900 for the year ended December 31, 2011, an increase of 10.5%. Average revenue per revenue generating horsepower per month declined from $14.70 for the year ended December 31, 2010 to $14.07 for the year ended December 31, 2011, a decrease of 4.3%. The decline in average revenue per revenue generating horsepower per month related primarily to the 3.7% increase in the estimated average horsepower per revenue generating compression unit, which was 667 and 692 at December 31, 2010 and 2011, respectively. While pricing for these services stabilized in mid-2010, compression units that were placed under service contracts during 2009 and 2010 were contracted at lower market rates. There were 888 revenue generating compression units at December 31, 2011 compared to 795 at December 31, 2010, an 11.7% increase. Revenue generating horsepower was 649,285 at December 31, 2011 compared to 533,692 at December 31, 2010, a 21.7% increase.

Parts and service revenue. Parts and service revenue was $4.8 million for the year ended December 31, 2011 compared to $2.2 million in 2010, or a 115.1% increase. A portion of retail service revenue, including billings for trucking and crane services increased $1.1 million during 2011, including $1.0 million recognized during the fourth quarter of 2011, due to the deployment and redeployment of compression units. These ancillary trucking and crane services, all of which are billed to customers, result in no gross operating margin.

Cost of operations, exclusive of depreciation and amortization. Cost of operations was $39.6 million for the year ended December 31, 2011 compared to $33.3 million for the year ended December 31, 2010, an increase of 19.0%. Approximately $1.8 million of this increase was related to higher expense levels under our operating lease facility with Caterpillar due to the addition of new compression units over the applicable periods. The amount drawn under this operating lease facility immediately prior to the termination of these lease schedules on December 15, 2011 was $39.9 million as compared to $28.9 million as of December 31, 2010. Approximately $0.8 million of the increase in cost of operations was related to higher lubrication oil expenses. Lubrication oil expenses increased due to a 21.4% increase in the average supplier price per gallon, offset by a 1.3% decrease in gallons consumed. Freight costs, all of which was billed to customers, increased $1.1 million due to the redeployment of compression units during the year ended December 31, 2011, as discussed above. Retail parts expense increased $1.1 million due to the sale of six spare engines. Other significant increases include (1) maintenance expenses increased by $0.3 million, (2) truck fleet fuel expenses increased by $0.4

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million, (3) supplies and equipment expenses increased by $0.2 million and (4) operating personnel salaries and benefits expense increased $0.4 million, all of which were attributable to the increase in the size of our fleet. The cost of operations was 40.2% of revenue for the year ended December 31, 2011 as compared to 36.2% for the year ended December 31, 2010.

Selling, general and administrative expense. Selling, general and administrative expense was $12.7 million for the year ended December 31, 2011 compared to $11.4 million for the year ended December 31, 2010, an increase of 11.9%. Selling, general and administrative expense represented 12.9% and 12.4% of revenue for the year ended December 31, 2011 and 2010, respectively. Approximately $1.0 million of the increase in selling, general and administrative expense relates to a fee for management services provided by an affiliate of our general partner. The selling, general and administrative employee headcount was 51 at December 31, 2011, a 30.8% employee increase from December 31, 2010, resulting in $0.7 million increase in salary and benefit expenses. The selling, general and administrative employee headcount increased to support continued growth of the business.

Restructuring charges. During the year ended December 31, 2011, we incurred $0.3 million of restructuring charges for severance and retention benefits related to the termination of certain administrative employees. These charges are reflected as restructuring charges in our consolidated statement of operations for the year ended December 31, 2011. These restructuring charges were paid in 2012.

Depreciation and amortization expense. Depreciation and amortization expense was $32.7 million for the year ended December 31, 2011 compared to $24.6 million for the year ended December 31, 2010, an increase of 33.2%. The push-down accounting treatment for the Holdings Acquisition resulted in the recognition of identified intangibles for customer relationships and the USA Compression trade name as of December 31, 2010 and the amortization of these identified intangibles over their useful lives began on January 1, 2011, of which $3.0 million was recognized for the year ended December 31, 2011. The remaining increase was related to an increase in property, plant and equipment over these periods.

Interest expense. Interest expense was $13.0 million for the year ended December 31, 2011 compared to $12.3 million for the year ended December 31, 2010, an increase of 5.6%. Included in interest expense is amortization of deferred loan costs of $1.5 million and $3.4 million for the years ended December 31, 2011 and 2010, respectively. Interest expense for both periods was related to borrowings under our revolving credit facility. Average borrowings outstanding under our revolving credit facility were $275.1 million for the year ended December 31, 2011 compared to $249.1 million for the year ended December 31, 2010. Our revolving credit facility had an interest rate of 3.02% and 3.76% at December 31, 2011 and 2010, respectively, and an average interest rate of 3.71% and 2.06%, excluding the effects from the interest rate swap instruments discussed below, for the year then ended, respectively, with the higher interest rate at December 31, 2011 due to the amendment of our revolving credit facility in December 2010. The November 2011 amendment to our credit facility increased the overall commitments under the facility from $400 million to $500 million and reduced our applicable margin for LIBOR loans from a range of 300 to 375 basis points above LIBOR to a range of 200 to 275 basis points above LIBOR, depending on our leverage ratio. The composite fixed interest rate for $140 million of notional coverage under three interest rate swap instruments was 2.52% at December 31, 2011 and 2010 plus the applicable margin of 2.75% and 3.50% at December 31, 2011 and December 31, 2010, respectively. As of December 31, 2010, we no longer designate our swap agreements as cash flow hedges. As a result, amounts paid or received from the interest rate swaps are charged or credited to interest expense. For the year ended December 31, 2011, we recorded a fair value gain of $2.6 million with respect to these swaps as a reduction in interest expense.

Income tax expense. We incurred approximately $155,000 in franchise tax for the years ended December 31, 2011 and 2010, as a result of the Texas franchise tax.

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Liquidity and Capital Resources

The following table summarizes our sources and uses of cash for the years ended December 31, 2012, 2011 and 2010, and our cash and working capital as of the end of the periods presented:

	Successor						Predecessor
	Year Ended December 31,						Year Ended December 31,
	2012			2011			2010
	(in thousands)						(in thousands)
Net cash provided by operating activities	$	41,974		$	33,782		$	38,572
Net cash used in investing activities	(178,589		)	(140,444		)	(18,768		)
Net cash provided by (used in) financing activities	136,618			106,662			(19,804		)

Net cash provided by operating activities. Net cash provided by operating activities increased to $42.0 million for the year ended December 31, 2012, from $33.8 million for the year ended December 31, 2011. The increase related primarily to a higher income level in 2012, offset by a $6.2 million higher use of working capital in 2012 primarily due to increased purchases and timing of payments for new compression unit equipment. Net cash provided by operating activities decreased to $33.8 million for the year ended December 31, 2011, from $38.6 million in 2010. The decrease related primarily to a lower income level, offset by $1.9 million of working capital generated for the year ended December 31, 2011.

Net cash used in investing activities. Net cash used in investing activities increased to $178.6 million for the year ended December 31, 2012, from $140.4 million for the year ended December 31, 2011. The increase related primarily to higher capital expenditures of $180.0 million during 2012, offset by $0.6 million of higher proceeds from the sale of equipment during 2012. Net cash used in investing activities increased to $140.4 million for the year ended December 31, 2011, from $18.8 million in 2010. The increase related to capital expenditures of $133.3 million and a compression unit purchase deposit of $8.0 million, for the year ended December 31, 2011, offset by the collection of funds in this period of $0.8 million related to the sale of compression units, 6 engines, and trucks. During 2010 we leased compression units from Caterpillar, which were later purchased by us in December 2011 for $43.0 million.

Net cash provided by (used in) financing activities. Net cash provided by financing activities increased to $136.6 million for the year ended December 31, 2012, from $106.7 million for the year ended December 31, 2011. The change was due to lower borrowings under our revolving credit facility for the year ended December 31, 2011 versus higher borrowings during 2012, due to higher levels of growth capital expenditures. Net cash provided by financing activities was $106.7 million for the year ended December 31, 2011, compared to net cash used in financing activities of $19.8 million in 2010. The change was due to net repayments of borrowings under our revolving credit facility for the year ended December 31, 2010 versus net borrowings during 2011, due to higher levels of growth capital expenditures.

Capital Expenditures

The compression 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 replace partially or fully depreciated assets, to maintain the operating capacity of our assets and extend their useful lives, or other capital expenditures that are incurred in maintaining our existing business and related cash flow; and

· expansion capital expenditures, which are capital expenditures made to expand the operating capacity or revenue generating capacity of existing or new assets, including by acquisition of compression units or through modification of existing compression units to increase their capacity.

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 year ended December 31, 2012 were $13.3 million.

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Given our growth objective, we anticipate that we will continue to make significant expansion capital expenditures. Our expansion capital expenditures were $180.0 million for the year ended December 31, 2012. On December 16, 2011, we entered into an agreement with one of our compression equipment suppliers to reduce certain previously made progress payments by $8 million and received a credit. We applied this $8 million credit to new compression units purchased from this supplier in the year ended December 31, 2012. Before the application of this credit, expansion capital expenditures were $174.6 million for the year ended December 31, 2012.

In addition to organic growth, we may also consider a variety of assets or businesses for potential acquisition. We expect to fund any future acquisitions primarily with capital from external financing sources, such as issuance of debt and equity securities, including our issuance of additional partnership units and future debt offerings.

Description of Revolving Credit Facility

We amended our revolving credit agreement in December 2010 to increase the overall commitments under the facility to $400 million and extend the term until October 5, 2015. On November 16, 2011, we amended the revolving credit agreement to increase the overall commitments under the facility from $400 million to $500 million and reduce our applicable margin for LIBOR loans from the previous range of 300 to 375 basis points above LIBOR to the new range of 200 to 275 basis points above LIBOR, depending on our leverage ratio. We further amended our revolving credit agreement on June 1, 2012 to increase the overall commitments under the facility from $500 million to $600 million. We have the option to increase the overall commitments under our revolving credit agreement by an additional $50 million, subject to receipt of lender commitments and satisfaction of other conditions. The revolving credit facility is available for our general partnership purposes, including working capital, capital expenditures, and distributions.

On June 1, 2012, we entered into the fourth amended and restated credit agreement in order to provide a covenant structure that is more appropriate for a public company than was our prior credit agreement. This amended and restated credit agreement became effective on January 18, 2013, the closing date of our initial public offering. On December 10, 2012, we amended the fourth amended and restated credit agreement to extend the periods during which the maximum funded debt to EBITDA ratio thresholds will apply. In addition, borrowing availability under the revolving credit facility was linked to our asset base, with the increased maximum capacity of $600 million (subject to a further potential increase of $50 million). The revolving credit facility is secured by a first priority lien against our assets and matures on October 5, 2015, at which point all amounts outstanding will become due.

Interest is due and payable in arrears and calculated, at our option, on either a floating rate basis, payable monthly or on a LIBOR basis, payable at the end of the applicable LIBOR period (1, 2, 3 or 6 months), but no less frequently than quarterly. LIBOR borrowings bear interest at LIBOR for the applicable period plus a margin of 2.50% to 1.75% based on our leverage ratio of funded debt to consolidated EBITDA, each as defined in the amended and restated credit agreement. Floating rate borrowings will bear interest at a rate per annum that is the higher of bank prime rate, the federal funds rate plus 0.50% or the LIBOR rate for a 1 month period plus 1%, without additional margin. The revolving credit facility includes a $20 million sub-line for issuing letters of credit for a fee at a per annum rate equal to the margin for LIBOR borrowings on the average daily undrawn stated amount of each letter of credit issued under the revolving credit facility.

Our amended and restated credit agreement permits us to make distributions of available cash to unitholders so long as (a) no default or event of default under the facility occurs or would result from the distribution, (b) immediately prior to and after giving effect to such distribution, we are in compliance with the facility’s financial covenants and (c) immediately after giving effect to such distribution, we have availability under the revolving credit facility of at least $20 million. In addition, the amended and restated credit agreement contains various covenants that may limit, among other things, our ability to:

· grant liens;

· make certain loans or investments;

· incur additional indebtedness or guarantee other indebtedness;

· subject to exceptions, enter into transactions with affiliates;

· sell our assets; or

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· acquire additional assets.

· Our amended and restated credit agreement also contains financial covenants requiring us to maintain:

· a minimum EBITDA to interest coverage ratio of 2.5 to 1.0; and

· a maximum funded debt to EBITDA ratio, determined as of the last day of each fiscal quarter, for the twelve month period then ending of (a) 5.50 to 1.0, with respect to any fiscal quarter ending on or after January 18, 2013, which was the closing date of our initial public offering, through March 31, 2014 or (b) 5.00 to 1.0, with respect to the fiscal quarter ending June 30, 2014 and each fiscal quarter thereafter, in each case subject to a provision for increases to such thresholds by 0.5 in connection with certain future acquisitions for the six consecutive month period following the period in which any such acquisition occurs.

If an event of default exists under the revolving credit facility, the lenders will be able to accelerate the maturity of the revolving credit facility and exercise other rights and remedies.

As of December 31, 2012, we were in compliance with all of the covenants under our current credit agreement.

Distribution Reinvestment Plan

We have filed a registration statement with the SEC to register the issuance of up to 4,150,000 of our common units in connection with a distribution reinvestment plan (“DRIP”). The DRIP provides unitholders of record and beneficial owners of our common units a means by which they can increase the number of common units they own by reinvesting the quarterly cash distributions they would otherwise receive into the purchase of additional common units. This registration statement became effective on January 30, 2013. As of March 22, 2013, no common units had been issued under this registration statement.

Total Contractual Cash Obligations. The following table summarizes our total contractual cash obligations as of December 31, 2012:

	Payments Due by Period
Contractual Obligations	Total		1 year		2 - 3 years		4 - 5 years		More than 5 years
	(in thousands)
Long-term debt(1)(5)	$	502,266	$	—	$	502,266	$	—	$	—
Interest on long-term debt obligations(2)	42,123		14,867		27,256		—		—
Equipment/capital purchases(3)	70,526		70,526		—		—		—
Operating lease obligations(4)	4,119		816		1,497		1,429		377
Total contractual cash obligations	$	619,034	$	86,209	$	531,019	$	1,429	$	377

(1) Represents future principal repayments under our revolving credit facility.

(2) Represents future interest payments under our revolving credit facility based on the interest rate at December 31, 2012 of 2.96%.

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

(4) Represents commitments for future minimum lease payments for noncancelable leases. We signed two new significant leases during 2012 for office space which contributed $2,206,988 to the total future lease payments.

(5) On January 18, 2013, we completed our IPO pursuant to a Registration Statement on Form S-1, as amended (Reg. No. 333-174803), and we used the net proceeds from the offering to repay $180,785,931 of indebtedness outstanding under our revolving credit facility.

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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 not entered into any transactions, agreements or other contractual arrangements that would result in off-balance sheet liabilities.

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 U.S. 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 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:

Depreciation

Property and equipment are stated at cost. Depreciation for financial reporting purposes is computed on the straight-line basis using estimated useful lives. If the actual useful life of our property and equipment is less than the estimate used for purposes of computing depreciation expense, we could experience an acceleration in depreciation expense. Major overhauls and improvements that extend the life of an asset are capitalized. As of December 31, 2012, we had 1,150 compression units that were subject to depreciation. Given the large number of compression units being depreciated, the impact of a particular unit incurring an actual useful life that is less than the estimated useful life would not have a material impact on our results of operations.

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, as well as in determining the allocation of goodwill to the appropriate reporting unit.

We perform an impairment test for goodwill annually or earlier if indicators of potential impairment exist. Because quoted market prices for the Partnership’s reporting unit were not available as of October 1, 2012, management applied judgment in determining if it is more likely than not that the fair value of the reporting unit is less than its carrying amount for purposes of performing the optional qualitative assessment for the annual goodwill impairment test. Management uses all available information to make this determination, including evaluating the macroeconomic environment and industry specific conditions at the assessment date of October 1. If for any reason the fair value of our goodwill declines below the carrying value in the future, we may incur charges for the impairment. There was no impairment recorded for goodwill for the years ended December 31, 2012, 2011 and 2010.

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, 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. There was no impairment recorded for the years ended December 31, 2012, 2011, 2010, and an impairment of $1.7 million was recorded for the year ended December 31, 2009.

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Allowances and Reserves

We maintain an allowance for bad debts based on specific customer collection issues and historical experience. On an ongoing basis, we conduct an evaluation of the financial strength of our customers based on payment history and specific identification and makes adjustments to the allowance as necessary. The allowance for doubtful accounts was $259,638, $260,598 and $173,808 at December 31, 2012, 2011 and 2010, respectively.

Revenue Recognition

Revenue is recognized by us using the following criteria: (i) persuasive evidence of an arrangement, (ii) delivery has occurred or services have been rendered, (iii) the customer’s price is fixed or determinable and (iv) collectability is reasonably assured.

Revenues from compression services are recognized as earned under our fixed fee contracts. Compression services are billed monthly in advance of the service period and are recognized as deferred revenue on the balance sheet until earned.

Recent Accounting Pronouncements

In September 2011, the FASB issued an update allowing entities to use a qualitative approach to test goodwill for impairment. Under this update, entities are permitted to first perform a qualitative assessment to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying value. If it is concluded that this is the case, it is necessary to perform the currently prescribed two-step goodwill impairment test. Otherwise, the two-step goodwill impairment test is not required. This update is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. Early adoption is permitted. We adopted this authoritative guidance in October 2011. The adoption of this new guidance did not have a material impact on our consolidated financial statements.

We qualify as an emerging growth company under Section 109 of the JOBS Act. An emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. In other words, an emerging growth company can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. However, we have chosen to “opt out” of such extended transition period, and as a result, are compliant with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. Section 108 of the JOBS Act provides that our decision to opt out of the extended transition period for complying with new or revised accounting standards is irrevocable.

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 in connection with our services and, accordingly, have no direct exposure to fluctuating commodity prices. The demand for our compression services depends upon the continued demand for, and production of, natural gas and crude oil. Lower natural gas prices 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. Please read Part I, Item 1A “Risk Factors — Risks Related to Our Business.” We do not intend to hedge our indirect exposure to fluctuating commodity prices.

Interest Rate Risk

We are exposed to market risk due to variable interest rates under our financing arrangements.

As of December 31, 2012 we had approximately $502.3 million of variable-rate outstanding indebtedness at a weighted-average interest rate of 3.0%. A 1% increase in the effective interest rate on our variable-rate outstanding debt at December 31, 2012 would result in an annual increase in our interest expense of approximately $5.0 million.

For further information regarding our use exposure to interest rate fluctuations on a portion of our debt obligations, see Note 4 to the Financial Statements.

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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 gas they owe to us, this 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 of this report.

ITEM 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

ITEM 9A. Controls and Procedures

Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Commission. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2012 at the reasonable assurance level.

Management’s Annual Report on Internal Control Over Financial Reporting

This annual report does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of the company’s registered public accounting firm due to a transition period established by rules of the Securities and Exchange Commission for newly public companies.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the last fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. Other Information

None.

PART III

ITEM 10. Directors, Executive Officers and Corporate Governance

Board of Directors

Our general partner, USA Compression GP, LLC, manages our operations and activities. Our general partner is not elected by our unitholders and is not subject to re-election on a regular basis in the future. Our general partner has a board of directors that manages our business.

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The board of directors of our general partner is comprised of eight members, all of whom have been designated by USA Compression Holdings and three of whom are independent as defined under the independence standards established by the New York Stock Exchange. The NYSE does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating committee.

Independent Directors. The board of directors of our general partner has determined that Robert F. End, William G. Manias and Forrest E. Wylie are independent directors under the standards established by the NYSE and the Exchange Act. The board of directors considered all relevant facts and circumstances and applied the independent guidelines of the NYSE and the Exchange Act in determining that none of these directors has any material relationship with us, our management, our general partner or its affiliates or our subsidiaries.

Audit Committee. The board of directors has appointed an audit committee comprised solely of directors who meet the independence and experience standards established by the NYSE and the Exchange Act. The audit committee consists of Robert F. End, William G. Manias and Forrest E. Wylie. Mr. Manias serves as chairman of the audit committee. The board of directors has determined that Mr. Manias is an “audit committee financial expert” as defined in Item 407(d)(5)(ii) of SEC Regulation S-K, and that each of Messrs. End, Manias and Wylie is “independent” within the meaning of the applicable NYSE and Exchange Act rules regulating audit committee independence. The audit committee assists the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The audit committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee. A copy of the charter of the audit committee is available under the Investor Relations tab on our website at www.usacpartners.com. We also will provide a copy of the charter of the audit committee to any of our unitholders without charge upon written request to Investor Relations, 100 Congress Avenue, Suite 450, Austin, TX 78701.

Compensation Committee. The NYSE does not require a listed limited partnership like us to have a compensation committee. However, our board has established a compensation committee to, among other things, oversee the compensation plans described below in Item 11 (“Executive Compensation”). The compensation committee establishes and reviews general policies related to our compensation and benefits. The compensation committee has the responsibility to determine and make recommendations to the board with respect to, the compensation and benefits of our board and executive officers. A copy of the charter of the compensation committee is available under the Investor Relations tab on our website at www.usacpartners.com. We also will provide a copy of the charter of the compensation committee to any of our unitholders without charge upon written request to Investor Relations, 100 Congress Avenue, Suite 450, Austin, TX 78701.

Conflicts Committee. As set forth in the GP Agreement, USA Compression GP, LLC may, from time to time, have a conflicts committee to which the board of directors will appoint independent directors and which may be asked to review specific matters that the board believes may involve conflicts of interest between us, our limited partners and USA Compression Holdings. The conflicts committee will determine the resolution of the conflict of interest in any manner referred to it in good faith. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates, including USA Compression Holdings, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors, and certain other requirements. Any matters approved by the conflicts committee in good faith will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.

Section 16(a) Beneficial Ownership Reporting Compliance

Under Section 16(a) of the Exchange Act, directors, officers and beneficial owners of 10 percent or more of our common units (“Reporting Persons”) are required to report to the SEC on a timely basis the initiation of their status as a Reporting Person and any changes with respect to their beneficial ownership of our common units. However, since we did not complete our IPO until January 18, 2013, Section 16(a) of the Exchange Act did not apply during the year ended December 31, 2012 to our directors, officers and beneficial owners of 10 percent or more of our common units.

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Corporate Governance Guidelines and Code of Ethics

The board of directors has adopted Corporate Governance Guidelines that outline important policies and practices regarding our governance and provide a framework for the function of the board of directors and its committees. The board of directors has also adopted a Code of Business Conduct and Ethics (the “Code”) that applies to USA Compression GP LLC and its subsidiaries and affiliates, including us, and to all of its and their employees, officers, including its principal executive officer, principal financial officer, principal accounting officer and directors. Copies of the Corporate Governance Guidelines and the Code are available under the Investor Relations tab on our website at www.usacpartners.com. We also will provide copies of the Corporate Governance Guidelines and the Code to any of our unitholders without charge upon written request to Investor Relations, 100 Congress Avenue, Suite 450, Austin, TX 78701.

Reimbursement of Expenses of Our General Partner

Our general partner will not receive any management fee or other compensation for its management of us. Our general partner and its affiliates will be reimbursed for all expenses incurred on our behalf, including the compensation of employees of USA Compression GP, LLC or its affiliates that perform services on our behalf. These expenses include all expenses necessary or appropriate to the conduct of our business and that are allocable to us. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. There is no cap on the amount that may be paid or reimbursed to our general partner or its affiliates for compensation or expenses incurred on our behalf.

Directors and Executive Officers

The following table shows information as of March 22, 2013 regarding the current directors and executive officers of USA Compression GP, LLC.

Name	Age	Position with USA Compression GP, LLC
Eric D. Long	54	President and Chief Executive Officer and Director
Joseph C. Tusa, Jr.	54	Vice President, Chief Financial Officer and Treasurer
J. Gregory Holloway	55	Vice President, General Counsel and Secretary
David A. Smith	50	Vice President and President, Northeast Region
Dennis J. Moody	55	Vice President—Operations Services
Kevin M. Bourbonnais	46	Vice President and Chief Operating Officer
Jim H. Derryberry	68	Director
Robert F. End	57	Director
William H. Shea, Jr.	57	Director
Andrew W. Ward	46	Director
Olivia C. Wassenaar	33	Director
William G. Manias	51	Director
Forrest E. Wylie	49	Director

The directors of our general partner hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the board of directors. There are no family relationships among any of the directors or executive officers of our general partner.

Eric D. Long has served as our President and Chief Executive Officer since September 2002 and has served as a director of USA Compression GP, LLC since June 2011. Mr. Long co-founded USA Compression in 1998 and has over 30 years of experience in the oil and gas industry. From 1980 to 1987, Mr. Long served in a variety of technical and managerial roles for several major pipeline and oil and natural gas producing companies, including Bass Enterprises Production Co. and Texas Oil & Gas. Mr. Long then served in a variety of senior officer level operating positions with affiliates of Hanover Energy, Inc., a company primarily engaged in the business of gathering, compressing and transporting natural gas. In 1993, Mr. Long co-founded Global Compression Services, Inc., a compression services company. Mr. Long was formerly on the board of directors of the Wiser Oil Company, an NYSE listed company from May 2001 until it was sold to Forest Oil Corporation in May 2004. Mr. Long received his bachelor’s degree, with honors, in Petroleum Engineering from Texas A&M University. He is a registered Professional Engineer in the state of Texas.

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As a result of his professional background, Mr. Long brings to us executive level strategic, operational and financial skills. These skills, combined with his over 30 years of experience in the oil and natural gas industry, including in particular his experience in the compression services sector, make Mr. Long a valuable member of our board.

Joseph C. Tusa, Jr. has served as our Vice President and Chief Financial Officer since joining us in January 2008. Mr. Tusa began his career with Arthur Andersen in Houston, Texas in its oil and gas exploration and production division. He then served as Chief Financial Officer of DSM Copolymer, Inc., a producer and global supplier of synthetic rubber. From 1997 to 2001, Mr. Tusa served as Senior Vice President of Business Operations for Metamor Worldwide, Inc., an IT services company that was listed on the NASDAQ exchange. From 2001 to December 2007, Mr. Tusa served as the Chief Financial Officer of Comsys IT Partners, Inc., an information technology staffing company and an affiliate of Metamor. Mr. Tusa received his B.B.A. from Texas State University and his M.B.A. from Louisiana State University. He is licensed as a Certified Public Accountant in the state of Texas.

J. Gregory Holloway has served as our Vice President, General Counsel and Secretary since joining us in June 2011. From September 2005 through June 2011, Mr. Holloway was a partner at Thompson & Knight LLP in its Austin office. His areas of practice at the firm included corporate, securities and merger and acquisition law. Mr. Holloway received his B.A. from Rice University and his J.D., with honors, from the University of Texas School of Law.

David A. Smith has served as our President, Northeast Region since joining us in November 1998 and was appointed corporate Vice President in June 2011. Mr. Smith has approximately 20 years of experience in the natural gas compression industry, primarily in operations and sales. From 1985 to 1989, Mr. Smith was a sales manager for McKenzie Corporation, a marketing company. From 1989 to 1996, Mr. Smith held positions of General Manager and Regional Manager of Northeast Division with Compressor Systems Inc., a fabricator and supplier of compression services. Mr. Smith was the Regional Manager in the northeast for Global Compression Services, Inc., a compression services company, and served in that capacity from 1996 to 1998. Mr. Smith received an associates degree in Automotive and Diesel Technology from Rosedale Technical Institute.

Dennis J. Moody has served as our Vice President—Operations Services since December 2011, as our General Manager, Central Region since December 2007 and previously served as sales manager since February 2002. Prior to this time, Mr. Moody served in positions of increasing responsibility since joining us in July 1999. Mr. Moody has over 30 years of experience with the operation, repair, sizing and sales of motor and electric driven compression equipment. From 1976 to 1979, Mr. Moody worked as an operator and repair mechanic and served on the overhaul crew at Mustang Fuel Corporation, an oil and gas company engaged in production, gathering, processing and marketing of natural gas. From 1979 to 1984, Mr. Moody managed the service, repair and parts distribution facilities for the drilling and industrial air compression distributors of Ingersoll-Rand and Sullair brand compressors in Oklahoma. From 1984 to July 1999, Mr. Moody served in an industrial and gas compression sales and sales support role at Bush Compression Industries, a fabricator of compression equipment.

Kevin M. Bourbonnais has served as our Vice President and Chief Operating Officer since June 2011. Mr. Bourbonnais has approximately 13 years of experience in the natural gas compression industry, in operations, marketing, manufacturing, engineering and sales. Mr. Bourbonnais served in various roles for the Royal Bank of Canada from 1990 to 1999. In 1999, he moved to Weatherford Global Compression, which was acquired by a predecessor to Exterran Holdings, Inc. in 2001. Mr. Bourbonnais was named Senior Vice President, Manufacturing in 2003, Senior Vice President, Operations in March 2007, Regional Vice President, Western Division in August 2007 and Vice President, Marketing & Product Strategy in January 2010, in which role he served until June 2011. Mr. Bourbonnais received a B.A. and an M.B.A. from the University of Calgary in 1989 and 2000, respectively.

Jim H. Derryberry has served as a director of USA Compression GP, LLC since January 2013. From February 2005 to October 2006, Mr. Derryberry served on the board of directors of Magellan GP, LLC, the general partner of Magellan Midstream Partners, L.P. Mr. Derryberry served as chief operating officer and chief financial officer of Riverstone Holdings, LLC until 2006 and currently serves as a special advisor. Prior to joining Riverstone, Mr. Derryberry was a managing director of J.P. Morgan, where he served as head of the Natural Resources and Power Group. Before joining J.P. Morgan, Mr. Derryberry was in the Goldman Sachs Global Energy and Power Group where he was responsible for mergers and acquisitions, capital markets financing and the management of relationships with major energy companies. He has also served as an advisor to the Russian government for energy privatization. Mr. Derryberry has served as a member of the Board of Overseers for the Hoover Institution at Stanford University and is a member of the Engineering Advisory Board at the University of Texas at Austin. He received his B.S. and M.S. degrees in engineering from the University of Texas at Austin and earned an M.B.A. from Stanford University.

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Mr. Derryberry brings significant knowledge and expertise to our board from his service on other boards and his years of experience in our industry including his useful insight into investments and proven leadership skills as a managing director of Riverstone Holdings, LLC. As a result of his experience and skills, we believe Mr. Derryberry is a valuable member of our board.

Robert F. End has served as a director of USA Compression GP, LLC since November 2012. Mr. End served as a director of Hertz Global Holdings, Inc. from December 2005 until August 2011. Mr. End was a Managing Director of Transportation Resource Partners, or TRP, a private equity firm from 2009 through 2011. Prior to joining TRP in 2009, Mr. End had been a Managing Director of Merrill Lynch Global Private Equity Division, or MLGPE, the private equity arm of Merrill Lynch & Co., Inc., where he served as Co-Head of the North American Region, and a Managing Director of Merrill Lynch Global Private Equity, Inc., the Manager of ML Global Private Equity Fund, L.P., a proprietary private equity fund which he joined in 2004. Previously, Mr. End was a founding Partner and Director of Stonington Partners Inc., a private equity firm established in 1994. Prior to leaving Merrill Lynch in 1994, Mr. End was a Managing Director of Merrill Lynch Capital Partners, Merrill Lynch’s private equity group. Mr. End joined Merrill Lynch in 1986 and worked in the Investment Banking Division before joining the private equity group in 1989. Mr. End received his A.B. from Dartmouth College and his M.B.A. from the Tuck School of Business Administration at Dartmouth College.

Mr. End brings significant knowledge and expertise to our board from his service on other boards and his years of experience with private equity groups, including his useful insight into investments and business development and proven leadership skills as Managing Director of MLGPE. As a result of this experience and resulting skills set, we believe Mr. End is a valuable member of our board.

William H. Shea, Jr. has served as a director of USA Compression GP, LLC since June 2011. Mr. Shea served as the President and Chief Operating Officer of Buckeye GP LLC and its predecessor entities, or Buckeye, from July 1998 to September 2000, as President and Chief Executive Officer of Buckeye from September 2000 to July 2007, and Chairman from May 2004 to July 2007. From August 2006 to July 2007, Mr. Shea served as Chairman of MainLine Management LLC, the general partner of Buckeye GP Holdings, L.P., and as President and Chief Executive Officer of MainLine Management LLC from May 2004 to July 2007. Mr. Shea served as a director of Penn Virginia Corp. from July 2007 to May 2010, and as President, Chief Executive Officer and director of the general partner of Penn Virginia GP Holdings, L.P. from March 2010 to March 2011. Mr. Shea has served as a director and the Chief Executive Officer of the general partner of Penn Virginia Resource Partners, L.P., or Penn Virginia, since March 2010. Mr. Shea has also served as a director of Kayne Anderson Energy Total Return Fund, Inc., and Kayne Anderson MLP Investment Company since March 2008 and Niska Gas Storage Partners LLC since May 2010. Mr. Shea has an agreement with Riverstone, pursuant to which he has agreed to serve on the boards of certain Riverstone portfolio companies. Mr. Shea received his B.A. from Boston College and his M.B.A. from the University of Virginia.

Mr. Shea’s experiences as an executive with both Penn Virginia and Buckeye, energy companies that operate across a broad spectrum of sectors, including coal, natural gas gathering and processing and refined petroleum products transportation, have given him substantial knowledge about our industry. In addition, Mr. Shea has substantial experience overseeing the strategy and operations of publicly traded partnerships. As a result of this experience and resulting skills set, we believe Mr. Shea is a valuable member of our board.

Andrew W. Ward has served as a director of USA Compression GP, LLC since June 2011. Mr. Ward has served as a Principal of Riverstone from 2002 until 2004, as a Managing Director since January 2005 and as a Partner and Managing Director since July 2009, where he focuses on the firm’s investment in the midstream sector of the energy industry. Mr. Ward served on the boards of directors of Buckeye and MainLine Management LLC from May 2004 to June 2006. Mr. Ward has also served on the board of directors of Gibson Energy Inc. since 2008 and Niska Gas Storage Partners LLC since May 2006. Mr. Ward received his A.B. from Dartmouth College and received his M.B.A. from the UCLA Anderson School of Management.

Mr. Ward’s experience in evaluating the financial performance and operations of companies in our industry make him a valuable member of our board. In addition, Mr. Ward’s work with Gibson Energy, Inc., Buckeye and Niska Gas Storage Partners LLC has given him both an understanding of the midstream sector of the energy business and of the unique issues related to operating publicly traded limited partnerships.

Olivia C. Wassenaar has served as a director of USA Compression GP, LLC since June 2011. Ms. Wassenaar was an Associate with Goldman, Sachs & Co. in the Global Natural Resources investment banking group from July 2007 to August 2008, where she focused on mergers, equity and debt financings and leveraged buyouts for energy, power and renewable energy companies. Ms. Wassenaar joined Riverstone in September 2008 as Vice President, and has served as a Principal since May 2010. In this capacity, she invests in and monitors investments in the midstream, exploration & production, and solar sectors of the energy industry. Ms.

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Wassenaar has also served on the board of directors of Northern Blizzard Resources Inc. since June 2011 and on the board of directors of Talos Energy LLC. Ms. Wassenaar received her A.B., magna cum laude, from Harvard College and earned an M.B.A. from the Wharton School of the University of Pennsylvania.

Ms. Wassenaar’s experience in evaluating financial and strategic options and the operations of companies in our industry and as an investment banker make her a valuable member of our board.

William G. Manias has served as a director of USA Compression GP, LLC since February 2013. From October 2009 until January 2013, Mr. Manias served as Senior Vice President and Chief Financial Officer of Crestwood Midstream Partners LP and its affiliates, where his general responsibilities included the partnership’s financial and treasury activities. Before joining Crestwood in, Mr. Manias was the Chief Financial Officer of TEPPCO Partners, L.P. from January 2006 through January 2009. From September 2004 until January 2006, he served as Vice President of Business Development and Strategic Planning at Enterprise Product Partners L.P. He previously served as Vice President and Chief Financial Officer of GulfTerra Energy Partners, L.P. from February 2004 to September 2004 at which time GulfTerra Energy Partners, L.P. was merged with Enterprise Product Partners L.P. Prior to GulfTerra Energy Partners, L.P., Mr. Manias held several executive management positions with El Paso Corporation. Prior to El Paso, he worked as an energy investment banker for J.P. Morgan Securities Inc. and its predecessor companies from May 1992 to August 2001. Mr. Manias earned a B.S.E. in civil engineering from Princeton University in 1984, a M.S. in petroleum engineering from Louisiana State University in 1986, and an M.B.A. from Rice University in 1992.

Mr. Manias’ expertise in a broad range of financial and commercial matters and his significant experience in public companies make him a valuable member of our board. In addition, Mr. Manias’ work with Crestwood Midstream Partners LP, TEPPCO Partners, L.P., Enterprise Product Partners, LP, GulfTerra Energy Partners, L.P. has given him both an understanding of the midstream sector of the energy business and of the unique issues related to operating publicly traded limited partnerships.

Forrest E. Wylie has served as a director of USA Compression GP, LLC since March 2013. Mr. Wylie has also served as the Non-Executive Chairman of the board of directors of Buckeye GP LLC, the general partner of Buckeye Partners, L.P., since February 10, 2012. He served as Chairman of the Board, CEO and a director of Buckeye GP LLC from June 25, 2007 to February 9, 2012. Mr. Wylie also served as a director of the general partner of Buckeye GP Holdings L.P., the former parent company of Buckeye GP (“BGH”) from June 25, 2007 until the merger of BGH with Buckeye Partners, L.P. on November 19, 2010. Prior to his appointment, he served as Vice Chairman of Pacific Energy Management LLC, an entity affiliated with Pacific Energy Partners, L.P., a refined product and crude oil pipeline and terminal partnership, from March 2005 until Pacific Energy Partners, L.P. merged with Plains All American, L.P. in November 2006. Mr. Wylie was President and CFO of NuCoastal Corporation, a midstream energy company, from May 2002 until February 2005. From November 2006 to June 25, 2007, Mr. Wylie was a private investor. Mr. Wylie served on the board of directors and the audit committee of Coastal Energy Company, a publicly traded entity, until April 2011. Mr. Wylie also served on board of directors and compensation and nominating and corporate governance committees of Eagle Bulk Shipping Inc. until May 2010.

Mr. Wylie’s experience in the energy industry, through his prior position as the CEO of a publicly traded partnership and the past employment described above, has given him both an understanding of the midstream sector of the energy business and of the unique issues related to operating publicly traded limited partnerships that make him a valuable member of our board.

ITEM 11. Executive Compensation

As is commonly the case for many publicly traded limited partnerships, we have no employees. Under the terms of our partnership agreement, we are ultimately managed by our general partner. We sometimes refer herein to USA Compression GP, LLC’s management and executive officers as “our management” and “our executive officers,” respectively.

Executive Compensation

We are an “emerging growth company” as defined under the Jumpstart Our Business Startups (JOBS) Act. As such, we are permitted to meet the disclosure requirements of Item 402 of Regulation S-K by providing the reduced disclosure required of a “smaller reporting company.”

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Executive Summary

This Executive Compensation disclosure provides an overview of the executive compensation program for our named executive officers identified below. Our general partner intends to provide our named executive officers with compensation that is significantly performance based. For the year ended December 31, 2012, our named executive officers, or our NEOs, were:

· Eric D. Long, President and Chief Executive Officer;

· Joseph C. Tusa, Jr., Vice President, Chief Financial Officer and Treasurer; and

· David A. Smith, Vice President and President, Northeast Region.

Summary Compensation Table

The following table sets forth certain information with respect to the compensation paid to our NEOs for the years ended December 31, 2011 and 2012.

Name and Principal Position	Year	Salary ($)	Unit Awards ($)(1)	Non-Equity Incentive Plan Compensation ($)(2)	All Other Compensation ($)		Total ($)
Eric D. Long	2012	400,000	—	400,000	26,500	(3)	826,500
President and Chief	2011	400,961	—	300,000	26,461	(4)	727,422
Executive Officer
Joseph C. Tusa, Jr.	2012	275,000	—	175,000	6,313	(5)	456,313
Vice President, Chief	2011	275,000	—	150,000	6,346	(6)	431,346
Financial Officer and Treasurer
David A. Smith	2012	250,000	—	400,000	20,045	(7)	670,045
Vice President and President,	2011	250,000	—	350,000	17,060	(8)	617,060
Northeast Region

(1) On December 23, 2010, each of our NEOs received awards of Class B Units in USA Compression Holdings. The Class B Units are intended to allow recipients to receive a percentage of profits generated by USA Compression Holdings over and above certain return hurdles, as described in more detail in the discussion under the heading “—Discretionary Long Term Equity Incentive Awards” below. No awards were made to our NEOs in 2011 or 2012.

(2) Represents the awards earned under annual incentive bonus programs and commission programs, as applicable, for the years ended December 31, 2011 and 2012. For a discussion of the determination of the 2012 bonus amounts, see “—Annual Performance Based Compensation for 2012” below.

(3) Includes $18,000 of automobile allowance and $8,500 of employer contributions under the 401(k) plan.

(4) Includes $18,000 of automobile allowance and $8,461 of employer contributions under the 401(k) plan.

(5) Includes $6,313 of employer contributions under the 401(k) plan.

(6) Includes $6,346 of employer contributions under the 401(k) plan.

(7) Includes $9,960 of automobile allowance and $10,085 of employer contributions under the 401(k) plan.

(8) Includes $9,960 of automobile allowance and $7,100 of employer contributions under the 401(k) plan.

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Narrative Disclosure to Summary Compensation Table

Elements of the Compensation Program

Compensation for our NEOs consists primarily of the elements, and their corresponding objectives, identified in the following table.

Compensation Element		Primary Objective
Base salary		To recognize performance of job responsibilities and to attract and retain individuals with superior talent.
Annual performance based compensation		To promote near-term performance objectives and reward individual contributions to the achievement of those objectives.
Discretionary long-term equity incentive awards		To emphasize long-term performance objectives, encourage the maximization of unitholder value and retain key executives by providing an opportunity to participate in the ownership of our partnership.
Severance benefits		To encourage the continued attention and dedication of key individuals and to focus the attention of key individuals when considering strategic alternatives.
Retirement savings (401(k)) plan		To provide an opportunity for tax-efficient savings.
Other elements of compensation and perquisites		To attract and retain talented executives in a cost-efficient manner by providing benefits with high perceived values at relatively low cost.

Base Compensation For 2012

Base salaries for our NEOs have generally been set at a level deemed necessary to attract and retain individuals with superior talent. Base salary increases are determined based upon the job responsibilities, demonstrated proficiency and performance of the executive officers and market conditions, each as assessed by the board of managers of USA Compression Holdings. No formulaic base salary increases are provided to the NEOs. Additionally, no changes to base salaries for our NEOs were made for the fiscal year ended December 31, 2012.

The current base salaries for our NEOs, including for our Chief Executive Officer, are set forth in the following table:

Name and Principal Position		Current Base Salary ($)
Eric D. Long
President and Chief Executive Officer		400,000
Joseph C. Tusa, Jr.
Vice President, Chief Financial Officer and Treasurer		275,000
David A. Smith
Vice President and President, Northeast Region		250,000

Annual Performance Based Compensation For 2012

Each of our NEOs participates in a discretionary annual incentive bonus compensation program, under which incentive awards are determined annually, with reference to target bonus amounts that are set forth in their employment agreements. For 2012, the target bonus amounts for each of our NEOs were as follows: Mr. Long: $300,000; Mr. Tusa: $110,000; and Mr. Smith: $120,000. In making individual annual bonus decisions, the Board of Managers of USA Compression Holdings, following the recommendations of our Chief Executive Officer, does not rely on pre-determined performance goals or targets. Instead, determinations regarding annual bonus compensation awards are based on a subjective assessment of all reasonably available information, including the applicable executive’s performance, business impact, contributions and leadership.

For 2012, our general partner’s Board of Managers determined to provide each NEO with a 2012 annual bonus award above the NEO’s target bonus, generally on what it viewed as strong leadership and overall financial performance. In addition, the Board of Managers sought to reward our NEOs for our operational results and significantly increased sales activity during the year. As a result of these considerations, Mr. Long received an annual incentive award equal to 133% of his target amount in recognition of his strong leadership in sales and operations, Mr. Smith received 167% of his target amount to recognize his strong sales performance and Mr.

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Tusa received an award equal to 159% of his target amount due to his leadership in building a strengthened financial and accounting team in 2012 and expanding and improving our credit facility.

Awards in 2012 were:

Eric D. Long	$	400,000
Joseph C. Tusa, Jr.	$	175,000
David A. Smith	$	200,000

Mr. Smith also receives commissions in an amount up to $200,000 annually based on a percentage of qualifying sales. Based on sales performance in 2012, as in prior recent years, Mr. Smith earned the maximum potential amount of commissions available under this arrangement.

Benefit Plans and Perquisites

We provide our executive officers, including our NEOs, with certain personal benefits and perquisites, which we do not consider to be a significant component of executive compensation but which we recognize are an important factor in attracting and retaining talented executives. Executive officers are eligible under the same plans as all other employees with respect to our medical, dental, vision, disability and life insurance plans and a defined contribution plan that is tax-qualified under Section 401(k) of the Internal Revenue Code and that we refer to as the 401(k) Plan. We also provide certain executive officers with an annual automobile allowance. We provide these supplemental benefits to our executive officers due to the relatively low cost of such benefits and the value they provide in assisting us in attracting and retaining talented executives. The value of personal benefits and perquisites we provide to each of our NEOs is set forth above in our “—Summary Compensation Table.”

Discretionary Long-Term Equity Incentive Awards

Prior to the Holdings Acquisition, our NEOs historically received various forms of equity compensation, in the form of both capital and profits interests in us and our predecessor entities, and in connection with the Holdings Acquisition, each of our NEOs re-invested a substantial portion of the cash proceeds received in respect of his prior equity interests in certain classes of capital or profit interest units in USA Compression Holdings.

Our NEOs were also granted Class B Units of USA Compression Holdings at the time of the Holdings Acquisition. In connection with the Holdings Acquisition in December 2010, the Board of Managers also reserved additional Class B Units for future grants to NEOs and other key employees.

The Class B Units are profits interests that allow our NEOs to participate in the increase in value of USA Compression Holdings over and above an 8% annual and cumulative preferred return hurdle. The grants have time-based vesting requirements and are designed to not only compensate but also to motivate and retain the recipients by providing an opportunity for equity ownership by our NEOs. The grants to our NEOs also provide our NEOs with meaningful incentives to increase unitholder value over time.

Generally, the Class B Units have vesting schedules that are designed to encourage NEOs’ continued employment or service with USA Compression Holdings or one of its affiliates, including us and our general partner. The Class B Units generally (i) vest twenty-five percent on the first anniversary of the date of grant (December 31, 2011 for grants made at the time of the Holdings Acquisition) and (ii) with respect to the remaining Class B Units, will vest in thirty-six monthly installments thereafter, subject to the NEO’s continued employment on each applicable vesting date. See “—Severance and Change in Control Arrangements” below for a description of the circumstances under which vesting of the Class B Units may be accelerated.

In connection with our initial public offering, we adopted a new long-term equity incentive plan, or the LTIP, which is discussed in more detail under “2013 Long-Term Incentive Plan” below.

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Outstanding Equity Awards at December 31, 2012

The following table provides information regarding the Class B Units in USA Compression Holdings held by the NEOs as of December 31, 2012. None of our NEOs held any option awards that were outstanding as of December 31, 2012.

	Unit Awards
Name	Number of Units That Have not Vested (#)		Market Value of Class B Units That Have Not Vested ($)(2)
Eric D. Long	231,250	(1)	—
Joseph C. Tusa, Jr.	62,500	(1)	—
David A. Smith	62,500	(1)	—

(1) Represents the number of Class B Units in USA Compression Holdings that have not vested as of December 31, 2012. These Class B Units will vest in thirty-six equal monthly installments on each monthly anniversary of December 31, 2011.

(2) As described in footnote 1 to the “—Summary Compensation Table” and in the discussion above under the heading “—Discretionary Long Term Equity Incentive Awards,” the Class B Units are intended to allow recipients to receive a percentage of profits generated by USA Compression Holdings over and above certain return hurdles. The Class B Units had no recognizable value as of December 31, 2012.

Severance and Change in Control Arrangements

Our NEOs are entitled to severance payments and benefits upon certain terminations of employment and, in certain cases, in connection with a change in control of Holdings.

Each NEO currently has an employment agreement with USA Compression Management Services, LLC, or USAC Management, which provides for severance benefits upon a termination of employment. On January 1, 2013, we entered into the services agreement with USAC Management, pursuant to which USAC Management provides to us and our general partner management, administrative and operating services and personnel to manage and operate our business. Pursuant to the services agreement, we will reimburse USAC Management for the allocable expenses for the services performed, including the salary, bonus, cash incentive compensation and other amounts paid to our NEOs. See Part III, Item 13 (“Certain Relationships and Related Transactions, and Director Independence”). In addition, pursuant to the Amended and Restated Limited Liability Company Agreement of USA Compression Holdings, or the Holdings Operating Agreement, our NEOs are entitled to accelerated vesting of certain Class B Units as described below.

Severance Arrangements

Each NEO’s employment agreement, dated as of December 23, 2010, has an initial four-year term and will be extended automatically for successive twelve month periods thereafter unless either party delivers written notice to the other within ninety days prior to the expiration of the then-current employment term. Upon termination of an NEO’s employment either by us for convenience or due to the NEO’s resignation for good reason, subject to the timely execution of a general release of claims, the NEO is entitled to receive (i) an amount equal to one times his annual base salary (plus in the case of Mr. Long an amount equal to one times his target annual bonus), payable in equal semi-monthly installments over one year following termination (or, if such termination occurs within two years following a change in control, in a lump sum within thirty days following the termination of employment) and (ii) continued coverage for twenty-four months (or, with respect to Mr. Long, thirty months) under our group medical plan in which the executive and any of his dependents were participating immediately prior to his termination. Continued coverage under our group medical plan is subsidized for the first twelve months following termination, and Mr. Long is entitled to reimbursement by us to the extent the cost of such coverage exceeds $1,200 per month for the remainder of the applicable period. Additionally, upon a termination of an NEO’s employment by us for convenience, by the NEO for good reason, or due to the NEO’s death or disability, the NEO is entitled to receive (i) an amount equal to one times his annual bonus (up to his target annual bonus) for the immediately preceding year and (ii) a pro-rata portion of any earned annual bonus for the year in which termination occurs (calculated with reference to the performance targets established by the Board of Managers of USA Compression Holdings for that year). During employment and for two years following termination, each NEO’s employment agreement prohibits him from competing with certain of our businesses.

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As used in the NEOs’ employment agreements, a termination for “convenience” means an involuntary termination for any reason, including a failure to renew the employment agreement at the end of an initial term or any renewal term, other than a termination for “cause.” “Cause” is defined in the NEOs’ employment agreements to mean (i) any material breach of the employment agreement or the Holdings Operating Agreement, by the executive, (ii) the executive’s breach of any applicable duties of loyalty to us or any of our affiliates, gross negligence or misconduct, or a significant act or acts of personal dishonesty or deceit, taken by the executive, in the performance of the duties and services required of the executive that has a material adverse effect on us or any of our affiliates, (iii) conviction or indictment of the executive of, or a plea of nolo contendere by the executive to, a felony, (iv) the executive’s willful and continued failure or refusal to perform substantially the executive’s material obligations pursuant to the employment agreement or the Holdings Operating Agreement or follow any lawful and reasonable directive from the Board of Managers of USA Compression Holdings or, as applicable, the Chief Executive Officer, other than as a result of the executive’s incapacity, or (v) a pattern of illegal conduct by the executive that is materially injurious to us or any of our affiliates or our or their reputation.

“Good reason” is defined in the NEOs’ employment agreements to mean (i) a material breach by us of the employment agreement, the Holdings Operating Agreement, or any other material agreement with the executive, (ii) any failure by us to pay to the executive the amounts or benefits to which he is entitled, other than an isolated and inadvertent failure not committed in bad faith, (iii) a material reduction in the executive’s duties, reporting relationships or responsibilities, (iv) a material reduction by us in the facilities or perquisites available to the executive or in the executive’s base salary, other than a reduction that is generally applicable to all similarly situated employees, or (v) the relocation of the geographic location of the executive’s principal place of employment by more than fifty miles from the location of the executive’s principal place of employment as of December 23, 2010. With respect to Mr. Long’s employment agreement, “good reason” also means the failure to appoint and maintain Mr. Long in the office of President and Chief Executive Officer.

Change in Control Benefits

Pursuant to the Holdings Operating Agreement, in the event of certain transactions, which could include a change in control, the vesting of certain Class B Units would be accelerated. The vesting of all unvested Class B Units would be accelerated either (i) upon a private liquidity event (generally defined as Riverstone’s sale of 50.1% of its equity interests in USA Compression Holdings for cash, other than in connection with an initial public offering of securities) or (ii) upon a termination of an NEO’s employment without cause or due to resignation by the executive for good reason, in each case, following a qualified public offering. In addition, upon a qualified public offering, 50% of each NEO’s unvested Class B Units would vest.

The Class B Units generally allow our NEOs to participate in the increase in value, following the December 23, 2010 grant date of such units, of the equity of USA Compression Holdings in excess of a specified hurdle, as described in more detail above under “—Discretionary Long-Term Equity Incentive Awards.”

Our initial public offering constituted a qualified public offering for purposes of certain vesting provisions of the NEO’s Class B Units, which resulted in 50% of each NEO’s unvested Class B Units vesting and, if an NEO’s employment is terminated by our general partner without cause or the NEO resigns for good reason, the remaining unvested Class B Units will vest in full. As used in the Holdings Operating Agreement, “good reason” and “cause” have the meanings set forth in each NEO’s employment agreement and described above in the section entitled “—Severance Arrangements.”

Director Compensation

For the year ended December 31, 2012, our NEOs who also served as directors did not receive additional compensation for their service as directors. Additionally, directors who were not officers, employees or paid consultants or advisors of us or our general partner did not receive compensation for their services as directors, except that Robert F. End received compensation for his service as a director during the quarter ended December 31, 2012, as set forth in the following table:

Name		Fees Earned or Paid in Cash ($)		Total
Robert F. End		18,750		18,750

Officers, employees or paid consultants or advisors of us or our general partner or its affiliates who also serve as directors do not receive additional compensation for their service as directors. Our directors who are not officers, employees or paid consultants or advisors of us or our general partner or its affiliates receive cash and equity based compensation for their services as directors. Our

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director compensation program consists of the following and will be subject to revision by the board of directors of our general partner from time to time:

· an annual cash retainer of $75,000,

· an additional annual retainer of $15,000 for service as the chair of any standing committee,

· meeting attendance fees of $2,000 per meeting attended, and

· an annual equity based award in the form of phantom units that will be granted under our LTIP, having a value as of the grant date of $75,000. Phantom unit awards are expected to be subject to vesting conditions and will be paid either on a current or deferred basis, in each case as will be determined at the time of grant of the awards.

Directors will also receive reimbursement for out-of-pocket expenses associated with attending such board or committee meetings and director and officer liability insurance coverage. Each director will be fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law.

2013 Long-Term Incentive Plan

In connection with our initial public offering, our general partner adopted the 2013 Long-Term Incentive Plan, or LTIP, primarily for the benefit of our subsidiaries’ and our general partner’s eligible officers, employees and directors.

The LTIP provides for the grant, from time to time at the discretion of the board of directors of our general partner, of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights and other unit-based awards. Subject to adjustment in the event of certain transactions or changes in capitalization, an aggregate of 1,410,000 common units may be delivered pursuant to awards under the LTIP. Units that are cancelled or forfeited will be available for delivery pursuant to other awards. Units that are withheld to satisfy our general partner’s tax withholding obligations or payment of an award’s exercise price will not be available for future awards. We expect that the LTIP will be administered by our general partner’s board of directors, though such administration function may be delegated to a committee that may be appointed by the board to administer the LTIP. The LTIP will be designed to promote our interests, as well as the interests of our unitholders, by rewarding the officers, employees and directors of us, our subsidiaries and our general partner for delivering desired performance results, as well as by strengthening our and our general partner’s ability to attract, retain and motivate qualified individuals to serve as directors, consultants and employees.

Unit Awards

The administrator of the LTIP may grant unit awards to eligible individuals under the LTIP. A unit award is an award of common units that are fully vested upon grant and are not subject to forfeiture. Unit awards may be paid in addition to, or in lieu of, cash that would otherwise be payable to a participant with respect to a bonus or an incentive compensation award. The unit award may be wholly discretionary in amount or it may be paid with respect to a bonus or an incentive compensation award the amount of which is determined based on the achievement of performance criteria or other factors.

Restricted Units and Phantom Units

A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the forfeiture restrictions lapse and the recipient holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or on a deferred basis upon specified future dates or events or, in the discretion of the administrator, cash equal to the fair market value of a common unit. The administrator of the LTIP may make grants of restricted and phantom units under the LTIP that contain such terms, consistent with the LTIP, as the administrator may determine are appropriate, including the period over which restricted or phantom units will vest. The administrator of the LTIP may, in its discretion, base vesting on the grantee’s completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon a change of control (as defined in the LTIP) or as otherwise described in an award agreement.

Distributions made by us with respect to awards of restricted units may be subject to the same vesting requirements as the restricted units. The administrator of the LTIP, in its discretion, may also grant tandem distribution equivalent rights with respect to

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phantom units. Distribution equivalent rights are rights to receive an amount equal to all or a portion of the cash distributions made on units during the period a phantom unit remains outstanding.

Unit Options and Unit Appreciation Rights

The LTIP also permits the grant of options and unit appreciation rights covering common units. Unit options represent the right to purchase a number of common units at a specified exercise price. Unit appreciation rights represent the right to receive the appreciation in the value of a number of common units over a specified exercise price, either in cash or in common units. Unit options and unit appreciation rights may be granted to such eligible individuals and with such terms as the administrator of the LTIP may determine, consistent with the LTIP; however, a unit option or unit appreciation right must have an exercise price equal to at least the fair market value of a common unit on the date of grant.

Other Unit-Based Awards

The LTIP also permits the grant of “other unit-based awards,” which are awards that, in whole or in part, are valued or based on or related to the value of a unit. The vesting of an other unit-based award may be based on a participant’s continued service, the achievement of performance criteria or other measures. On vesting or on a deferred basis upon specified future dates or events, an other unit-based award may be paid in cash and/or in units (including restricted units), as the administrator of the LTIP may determine.

Source of Common Units; Cost

Common units to be delivered with respect to awards may be newly issued units, common units acquired by us or our general partner in the open market, common units already owned by our general partner or us, common units acquired by our general partner directly from us or any other person or any combination of the foregoing. With respect to awards made to employees of our general partner, our general partner will be entitled to reimbursement by us for the cost incurred in acquiring such common units or, with respect to unit options, for the difference between the cost it incurs in acquiring these common units and the proceeds it receives from an optionee at the time of exercise of an option. Thus, we will bear the cost of all awards under the LTIP. If we issue new common units with respect to these awards, the total number of common units outstanding will increase, and our general partner will remit the proceeds it receives from a participant, if any, upon exercise of an award to us. With respect to any awards settled in cash by our general partner, our general partner will be entitled to reimbursement by us for the amount of the cash settlement.

Amendment or Termination of Long-Term Incentive Plan

The administrator of the LTIP, at its discretion, may terminate the LTIP at any time with respect to the common units for which a grant has not previously been made. The LTIP will automatically terminate on the tenth anniversary of the date it was initially adopted by our general partner. The administrator of the LTIP will also have the right to alter or amend the LTIP or any part of it from time to time or to amend any outstanding award made under the LTIP, provided that no change in any outstanding award may be made that would materially impair the vested rights of the participant without the consent of the affected participant or result in taxation to the participant under Section 409A of the Code.

ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of our units as of March 22, 2013 held by:

· each person who beneficially owns 5% or more of our outstanding units;

· all of the directors of USA Compression GP, LLC;

· each executive officer of USA Compression GP, LLC; and

· all directors and officers of USA Compression GP, LLC as a group.

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Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them and their address is 100 Congress Avenue, Suite 450, Austin, Texas 78701.

Name of Beneficial Owner	Common Units Beneficially Owned		Percentage of Common Units Beneficially Owned		Subordinated Units Beneficially Owned	Percentage of Subordinated Units Beneficially Owned		Percentage of Common and Subordinated Units Beneficially Owned
USA Compression Holdings(1)	4,048,588		26.9	%	14,048,588	100.0	%	62.2	%
Eric D. Long	12,500	(2)	*		—	—		—
Joseph C. Tusa, Jr.	—		—		—	—		—
J. Gregory Holloway	—		—		—	—		—
David A. Smith	—		—		—	—		—
Dennis J. Moody	—		—		—	—		—
Kevin M. Bourbonnais	—		—		—	—		—
William H. Shea, Jr.	—		—		—	—		—
Olivia C. Wassenaar	—		—		—	—		—
Andrew W. Ward	—		—		—	—		—
Robert F. End	10,000		*		—	—		—
Jim H. Derryberry	—		—		—	—		—
William G. Manias	—		—		—	—		—
Forrest E. Wylie	954	(3)	*		—	—		—
All directors and officers as a group (13 persons)	23,454		*		—	—		—

* Less than 1%.

(1) Eric D. Long, Joseph C. Tusa, Jr., Kevin M. Bourbonnais, J. Gregory Holloway, David A. Smith and Dennis J. Moody, each of whom are executive officers of our general partner, Aladdin Partners, L.P., a limited partnership affiliated with Mr. Long, and R/C IV USACP Holdings, L.P., or R/C Holdings, own equity interests in USA Compression Holdings. USA Compression Holdings is managed by a three person board of managers consisting of Mr. Long, Mr. Ward and Ms. Wassenaar. The board of managers exercises investment discretion and control over the units held by USA Compression Holdings.

R/C Holdings is the record holder of approximately 97.6% of the limited liability company interests of USA Compression Holdings and is entitled to elect a majority of the members of the board of managers of USA Compression Holdings. R/C Holdings is an investment partnership affiliated with Riverstone/Carlyle Global Energy and Power Fund IV, L.P., or R/C IV. Management and control of R/C Holdings is vested in its general partner, which is in turn managed and controlled by its general partner, R/C Energy GP IV, LLC. R/C Energy GP IV, LLC is managed by an eight person management committee that includes Andrew W. Ward. The principal business address of R/C Energy GP IV, LLC is 712 Fifth Avenue, 51st Floor, New York, New York 10019.

Mr. Long, Mr. Ward and Ms. Wassenaar, each of whom are members of the board of directors of our general partner, each disclaim beneficial ownership of the units owned by USA Compression Holdings.

(2) Includes 10,000 common units held by certain trusts of which Mr. Long is the trustee and 1,500 common units held by Mr. Long’s spouse.

(3) Under the regulations of the SEC, common units are deemed to be “beneficially owned” by a person if he directly or indirectly has or shares the power to vote or dispose of, or to direct the voting or disposition of, such common units, whether or not he has any pecuniary interest in such common units, or if he has the right to acquire the power to vote or dispose of such common units within 60 days. On March 13, 2013, the board of directors granted Mr. Wylie 3,816 phantom units in lieu of his annual cash retainer. Such phantom units will vest in equal installments on each of March 31, 2013, June 30, 2013, September 30, 2013 and December 31, 2013.

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Securities Authorized for Issuance Under Equity Compensation Plans

In connection with the consummation of our initial public offering on January 18, 2013, the board of directors of our general partner adopted the 2013 Long-Term Incentive Plan. The following table provides certain information with respect to this plan as of March 22, 2013:

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights	Number of securities remaining available for future issuance under equity compensation plan (excluding securities reflected in the first column)
Equity compensation plans approved by security holders	¾	N/A	¾
Equity compensation plans not approved by security holders	224,734	N/A	1,185,266

ITEM 13. Certain Relationships and Related Transactions, and Director Independence

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

In connection with our formation and initial public offering, we and other parties have entered into the following agreements. These agreements were not the result of arm’s length negotiations, and they, or any of the transactions that they provide for, may not be effected on terms as favorable to the parties to these agreements as could have been obtained from unaffiliated third parties.

Services Agreement

We entered into a services agreement with USA Compression Management Services, LLC, or USAC Management, a wholly owned subsidiary of our general partner, effective on January 1, 2013, pursuant to which USAC Management provides to us and our general partner management, administrative and operating services and personnel to manage and operate our business. We or one of our subsidiaries pays USAC Management for the allocable expenses it incurs in its performance under the services agreement. These expenses include, among other things, salary, bonus, cash incentive compensation and other amounts paid to persons who perform services for us or on our behalf and other expenses allocated by USAC Management to us. USAC Management has substantial discretion to determine in good faith which expenses to incur on our behalf and what portion to allocate to us.

The services agreement has an initial term of five years, at which point it automatically renews for additional one year terms. The services agreement may be terminated at any time by (i) the board of directors of our general partner upon 120 days’ written notice for any reason in its sole discretion or (ii) USAC Management upon 120 days’ written notice if (a) we or our general partner experience a change of control, (b) we or our general partner breach the terms of the services agreement in any material respect following 30 days’ written notice detailing the breach (which breach remains uncured after such period), (c) a receiver is appointed for all or substantially all of our or our general partner’s property or an order is made to wind up our or our general partner’s business; (d) a final judgment, order or decree that materially and adversely affects the ability of us or our general partner to perform under the services agreement is obtained or entered against us or our general partner, and such judgment, order or decree is not vacated, discharged or stayed; or (e) certain events of bankruptcy, insolvency or reorganization of us or our general partner occur. USAC Management will not be liable to us for their performance of, or failure to perform, services under the services agreement unless its acts or omissions constitute gross negligence or willful misconduct.

Management Fees

For the year ended December 31, 2012, we incurred $1,000,000 of expenses related to a management fee under an agreement between USA Compression Holdings, LLC and certain of its affiliates. After the completion of our initial public offering, we and our subsidiaries are no longer required to pay this management fee.

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Relationship with PVR Partners

Mr. Shea, a director of USA Compression GP, LLC, is currently a director and the chief executive officer of the general partner of PVR Partners, L.P., or PVR. In 2008, PVR acquired the business of one of our compression services customers and, after such acquisition, has continued to purchase compression services from us. For the years ended December 31, 2012 and 2011, subsidiaries of PVR made compression services payments to us of approximately $2.2 million and $1.3 million, respectively.

Procedures for Review, Approval and Ratification of Related Person Transactions

The board of directors of our general partner adopted a code of business conduct and ethics in connection with the closing of our initial public offering that provides that the board of directors of our general partner or its authorized committee will periodically review all related person transactions that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. If the board of directors of our general partner or its authorized committee considers ratification of a related person transaction and determines not to so ratify, the code of business conduct and ethics provides that our management will make all reasonable efforts to cancel or annul the transaction.

The code of business conduct and ethics provides that, in determining whether or not to recommend the initial approval or ratification of a related person transaction, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to: (i) whether there is an appropriate business justification for the transaction; (ii) the benefits that accrue to us as a result of the transaction; (iii) the terms available to unrelated third parties entering into similar transactions; (iv) the impact of the transaction on a director’s independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediately family member of a director is a partner, shareholder, member or executive officer); (v) the availability of other sources for comparable products or services; (vi) whether it is a single transaction or a series of ongoing, related transactions; and (vii) whether entering into the transaction would be consistent with the code of business conduct and ethics.

The code of business conduct and ethics described above was adopted in connection with the closing of our initial public offering, and as a result the transactions described above were not reviewed under such policy. The transactions described above were not approved by an independent committee of our board of directors and the terms were determined by negotiation among the parties.

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates, including USA Compression Holdings, on the one hand, and our partnership and our limited partners, on the other hand. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us and our limited partners, on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to our unitholders for actions taken by our general partner that, without those limitations, might constitute breaches of its fiduciary duty.

Our general partner will not be in breach of its obligations under our partnership agreement or its fiduciary duties to us or our unitholders if the resolution of the conflict is:

· approved by the conflicts committee of our general partner, although our general partner is not obligated to seek such approval;

· approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

· on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

· fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

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Our general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of its board of directors. In connection with a situation involving a conflict of interest, any determination by our general partner involving the resolution of the conflict of interest must be made in good faith, provided that, if our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will conclusively be deemed that, in making its decision, the board of directors acted in good faith. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee may consider any factors that it determines in good faith to be appropriate when resolving a conflict. When our partnership agreement provides that someone act in good faith, it requires that person to reasonably believe he is acting in the best interests of the partnership.

Director Independence

Please see Part III, Item 10 (“Directors, Executive Officers and Corporate Governance—Board of Directors”) of this report for a discussion of director independence matters.

ITEM 14. Principal Accountant Fees and Services

The following table presents fees for professional services rendered by our independent registered public accounting firm, KPMG LLP during the years ended December 31, 2012 and 2011:

	Year Ended December 31,
	2012		2011
	(in millions)
Audit Fees (1)	$	0.5	$	0.7
Audit-Related Fees	¾		¾
Tax Fees	¾		¾
All Other Fees	¾		¾
Total	$	0.5	$	0.7

(1) Expenditures classified as “Audit Fees” above were billed to USA Compression Partners, LP and include the audit of our annual financial statements and work related to the registration statement on Form S-1 filed in connection with our initial public offering

Our audit committee has adopted an audit committee charter, which is available on our website, which requires the audit committee to pre-approve all audit and non-audit services to be provided by our independent registered public accounting firm. The audit committee does not delegate its pre-approval responsibilities to management or to an individual member of the audit committee. Since our Audit Committee was not established until January 2013, none of the services reported in the audit, tax and all other fees categories above were pre-approved by the audit committee.

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PART IV

ITEM 15. Exhibits and Financial Statement Schedules

(a) Documents filed as a part of this report.

1. Financial Statements. See “Index to Consolidated Financial Statements” set forth on Page F-1.

2. Financial Statement Schedule

All other schedules have been omitted because they are not required under the relevant instructions.

3. Exhibits

The following documents are filed as exhibits to this report:

Exhibit Number		Description
3.1		Certificate of Limited Partnership of USA Compression Partners, LP (incorporated by reference to Exhibit 3.1 to Amendment No. 3 of the Partnership’s registration statement on Form S-1 (Registration No. 333-174803) filed on December 21, 2011)
3.2		First Amended and Restated Agreement of Limited Partnership of USA Compression Partners, LP (incorporated by reference to Exhibit 3.1 to the Partnership’s Current Report on Form 8-K (File No. 001-35779) filed on January 18, 2013)
10.1		Fourth Amended and Restated Credit Agreement (incorporated by reference to Exhibit 10.9 to Amendment No. 6 of the Partnership’s registration statement on Form S-1 (Registration No. 333-174803) filed on June 8, 2012)
10.2		First Amendment to Fourth Amended and Restated Credit Agreement (incorporated by reference to Exhibit 10.10 to Amendment No. 10 of the Partnership’s registration statement on Form S-1 (Registration No. 333-174803) filed on January 7, 2013)
10.3†		Long Term Incentive Plan of USA Compression Partners, LP (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (File No. 001-35779) filed on January 18, 2013)
10.4†		Employment Agreement, dated December 23, 2010, between USA Compression Partners, LLC and Eric D. Long (incorporated by reference to Exhibit 10.5 to Amendment No. 4 of the Partnership’s registration statement on Form S-1 (Registration No. 333-174803) filed on February 13, 2012)
10.5†		Employment Agreement, dated December 23, 2010, between USA Compression Partners, LLC and Joseph C. Tusa, Jr. (incorporated by reference to Exhibit 10.6 to Amendment No. 4 of the Partnership’s registration statement on Form S-1 (Registration No. 333-174803) filed on February 13, 2012)
10.6†		Employment Agreement, dated December 23, 2010, between USA Compression Partners, LLC and David A. Smith (incorporated by reference to Exhibit 10.8 to Amendment No. 4 of the Partnership’s registration statement on Form S-1 (Registration No. 333-174803) filed on February 13, 2012)
10.7		Services Agreement, dated effective January 1, 2013, by and among USA Compression Partners, LP, USA Compression GP, LLC and USA Compression Management Services, LLC (incorporated by reference to Exhibit 10.11 to Amendment No. 10 of the Partnership’s registration statement on Form S-1 (Registration No. 333-174803) filed on January 7, 2013)
10.8†*		USA Compression Partners, LP 2013 Long-Term Incentive Plan—Form of Director Phantom Unit Agreement
10.9†*		USA Compression Partners, LP 2013 Long-Term Incentive Plan—Form of Employee Phantom Unit Agreement
10.10†*		USA Compression Partners, LP 2013 Long-Term Incentive Plan—Form of Director Phantom Unit Agreement (in lieu of Annual Cash Retainer)
21.1*		List of subsidiaries of USA Compression Partners, LP
23.1*		Consent of KPMG LLP
31.1*		Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934
31.2*		Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934
32.1*#		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2*#		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

USA Compression Partners, LP

By:	USA Compression GP, LLC,
	its General Partner


By:	/s/ Eric D. Long
	Eric D. Long
	President and Chief Executive Officer
	(Principal Executive Officer)

Date: March 28, 2013

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 28, 2013.

Signature		Title

/s/ Eric D. Long		President and Chief Executive Officer (Principal Executive
Eric D. Long		Officer) and Director

/s/ Joseph C. Tusa, Jr.		Vice President, Chief Financial Officer and Treasurer (Principal
Joseph C. Tusa, Jr.		Financial Officer and Principal Accounting Officer)

/s/ Robert F. End		Director
Robert F. End

/s/ Jim H. Derryberry		Director
Jim H. Derryberry

/s/ William G. Manias		Director
William G. Manias

/s/ William H. Shea, Jr.		Director
William H. Shea, Jr.

/s/ Olivia C. Wassenaar		Director
Olivia C. Wassenaar

/s/ Andrew W. Ward		Director
Andrew W. Ward

/s/ Forrest E. Wylie		Director
Forrest E. Wylie

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USA COMPRESSION PARTNERS, LP AND SUBSIDIARIES
(FORMERLY USA COMPRESSION HOLDINGS, LP)
Consolidated Balance Sheets
December 31, 2012 and 2011

	Successor
	2012		2011
Assets
Current assets:
Cash and cash equivalents	$	6,500	$	3,000
Accounts receivable:
Trade	8,618,164		8,872,159
Other	136,907		51,606
Inventory	4,215,267		3,211,463
Prepaid expenses	1,799,652		1,646,490
Total current assets	14,776,490		13,784,718
Property and equipment, net	610,129,710		456,648,605
Identifiable intangible asset-customer relationships	67,200,000		69,600,000
Identifiable intangible asset-trade names	14,352,000		14,976,000
Goodwill	157,075,195		157,075,195
Other assets	9,111,350		15,791,458
Total assets	$	872,644,745	$	727,875,976

Liabilities and Partners’ Capital
Current liabilities:
Accounts payable	$	10,650,727	$	10,050,835
Accrued liabilities	5,590,028		4,231,821
Deferred revenue	10,611,395		8,577,789
Current portion of long-term debt	—		39,067
Liability from interest rate swaps	—		2,180,049
Total current liabilities	26,852,150		25,079,561
Long-term debt	502,266,210		363,773,468
Partners’ capital:
Limited partners’ capital	341,130,323		336,671,919
General partner’s capital	2,396,062		2,351,028
Total partners’ capital	343,526,385		339,022,947
Total liabilities and partners’ capital	$	872,644,745	$	727,875,976

See accompanying notes to consolidated financial statements.

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USA COMPRESSION PARTNERS, LP AND SUBSIDIARIES
(FORMERLY USA COMPRESSION HOLDINGS, LP)
Consolidated Statements of Operations
Years ended December 31, 2012, 2011 and 2010

	Successor						Predecessor
	2012			2011			2010
Revenues:
Contract operations	$	116,373,114		$	93,896,230		$	89,785,052
Parts and service	2,413,611			4,824,489			2,243,119
Total revenues	118,786,725			98,720,719			92,028,171
Costs and expenses:
Cost of operations, exclusive of depreciation and amortization	37,795,685			39,605,337			33,291,543
Selling, general, and administrative	18,268,003			12,725,930			11,369,996
Restructuring charges	—			300,000			—
Depreciation and amortization	41,880,318			32,737,779			24,569,323
Loss (Gain) on sale of assets	266,117			178,369			(89,799		)
Total costs and expenses	98,210,123			85,547,415			69,141,063
Operating income	20,576,602			13,173,304			22,887,108
Other income (expense):
Interest expense	(15,904,899		)	(12,970,019		)	(12,279,162		)
Other	27,775			20,828			26,691
Total other expense	(15,877,124		)	(12,949,191		)	(12,252,471		)
Net income before income tax expense	4,699,478			224,113			10,634,637
Income tax expense	196,040			154,872			155,179
Net income	$	4,503,438		$	69,241		$	10,479,458
Net income allocated to general partner	$	45,034		$	692		$	104,795
Net income available for limited partners	$	4,458,404		$	68,549		$	10,374,663

See accompanying notes to consolidated financial statements.

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USA COMPRESSION PARTNERS, LP AND SUBSIDIARIES
(FORMERLY USA COMPRESSION HOLDINGS, LP)
Consolidated Statements of Changes in Partners’ Capital
Years ended December 31, 2012, 2011 and 2010

	General partner			Limited partners		Accumulated other comprehensive income (loss)			Total partners’ capital
Partners’ capital (deficit), December 31, 2009, predecessor	$	(321,516	)	$	76,062,403	$	(3,114,411	)	$	72,626,476
Other comprehensive income	—			—		(1,694,161		)	(1,694,161		)
Share based compensation expense	—			382,435		—			382,435
Net income	104,795			10,374,663		—			10,479,458
Partners’ capital (deficit), December 31, 2010, predecessor	(216,721		)	86,819,501		(4,808,572		)	81,794,208
Impact of change in control	2,567,057			249,783,869		4,808,572			257,159,498
Partners’ capital opening balance, December 31, 2010, successor	2,350,336			336,603,370		—			338,953,706
Net income	692			68,549		—			69,241
Partners’ capital, December 31, 2011, successor	2,351,028			336,671,919		—			339,022,947
Net income	45,034			4,458,404		—			4,503,438
Partners’ capital, December 31, 2012, successor	$	2,396,062		$	341,130,323	$	—		$	343,526,385

See accompanying notes to consolidated financial statements.

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USA COMPRESSION PARTNERS, LP AND SUBSIDIARIES
(FORMERLY USA COMPRESSION HOLDINGS, LP)
Consolidated Statements of Cash Flows
Years ended December 31, 2012, 2011 and 2010

	Successor						Predecessor
	2012			2011			2010
Cash flows from operating activities:
Net income	$	4,503,438		$	69,241		$	10,479,458
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	41,880,318			32,737,779			24,569,323
Amortization of debt issue costs, discount, other comprehensive loss	1,856,063			1,528,928			3,449,633
Share-based compensation expense	—			—			382,435
Net (gain) loss on sale of assets	266,117			178,369			(89,799		)
Net gain on change in fair value of interest rate swap	(2,180,049		)	(2,628,523		)	—
Changes in assets and liabilities:
Accounts receivable and advances to employees	168,694			(975,784		)	(335,997		)
Inventory	(1,003,804		)	1,973,863			503,111
Prepaids	(153,162		)	(218,507		)	(18,128		)
Other noncurrent assets	(1,315,493		)	(2,600,602		)	1,700
Accounts payable	(5,340,257		)	1,986,800			(824,779		)
Accrued liabilities and deferred revenue	3,291,813			1,730,287			455,335
Net cash provided by operating activities	41,973,678			33,781,851			38,572,292
Cash flows from investing activities:
Capital expenditures	(179,976,735		)	(133,263,929		)	(18,885,762		)
Compression unit purchase deposit	—			(7,974,720		)	—
Proceeds from sale of property and equipment	1,388,065			795,065			117,955
Net cash used in investing activities	(178,588,670		)	(140,443,584		)	(18,767,807		)
Cash flows from financing activities:
Proceeds from short-term and long-term debt	261,135,162			209,164,480			82,176,687
Payments on short-term and long-term debt	(122,681,487		)	(101,166,549		)	(93,883,701		)
Financing costs	(1,835,183		)	(1,336,198		)	(8,097,473		)
Net cash provided by (used in) financing activities	136,618,492			106,661,733			(19,804,487		)
Increase (decrease) in cash and cash equivalents	3,500			—			(2		)
Cash and cash equivalents, beginning of year	3,000			3,000			3,002
Cash and cash equivalents, end of year	$	6,500		$	3,000		$	3,000
Supplemental cash flow information:
Cash paid for interest	$	16,086,012		$	13,727,393		$	8,720,584
Cash paid for taxes	$	154,785		$	155,183		$	190,226

See accompanying notes to consolidated financial statements.

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USA COMPRESSION PARTNERS, LP AND SUBSIDIARIES
(FORMERLY USA COMPRESSION HOLDINGS, LP)
Notes to Consolidated Financial Statements
December 31, 2012, 2011 and 2010

(1) The Partnership, Nature of Business, and Recent Transactions

USA Compression Partners, L.P., a Texas limited partnership (the Former Partnership), was formed on July 10, 1998. In October 2008, the Former Partnership entered into several transactions through which the Former Partnership was reorganized into a holding company, USA Compression Holdings, LP (the Partnership). The owners of the Former Partnership caused the Partnership to be formed as a Texas limited partnership to conduct its affairs as the holding company of an operating and leasing structure of entities. The Former Partnership’s owners then transferred their equity interests in the Former Partnership to the Partnership in exchange for identical interests in the Partnership. The Former Partnership became a wholly owned subsidiary of the Partnership, and was converted into USA Compression Partners, LLC, a Delaware, single-member, limited liability company (Operating Subsidiary) to continue providing compression services to customers of the Former Partnership. Concurrently, the Operating Subsidiary formed a wholly owned subsidiary, USAC Leasing, LLC, as a Delaware limited liability company (Leasing Subsidiary), and agreed to sell its then existing compressor fleet to the Leasing Subsidiary for assumption of debt relating to the then existing fleet. The Leasing Subsidiary agreed to lease the compressor fleet to the Operating Subsidiary for use in providing compression services to its customers. The consolidated financial statements as of December 31, 2012, 2011 and 2010 include the accounts of the Partnership, the Operating Subsidiary and the Leasing Subsidiary and all intercompany balances and transactions have been eliminated in consolidation. The Partnership joined the Operating Subsidiary’s revolving credit facility as a guarantor and the Leasing Subsidiary joined the revolving credit facility as a co-borrower (see note 4). On June 7, 2011, the Partnership converted from a Texas limited partnership into a Delaware limited partnership and changed its name from USA Compression Holdings, LP to USA Compression Partners, LP.

The Partnership, together with the Operating Subsidiary and the Leasing Subsidiary, primarily provides natural gas compression services under term contracts with customers in the oil and gas industry, using natural gas compressor packages that it designs, engineers, operates and maintains.

In September 2010, the Partnership issued 200,000 Class C units representing capital interests in the Partnership to its chief executive officer pursuant to his employment agreement.

Partnership net income (loss) is allocated to the partners in proportion to their respective interest in the Partnership.

On November 29, 2010, the Partnership and each of its partners entered into a unit purchase agreement with USA Compression Holdings, LLC in which USA Compression Holdings, LLC would acquire, subject to certain conditions, all of the limited partner interest of the Partnership and an affiliate of USA Compression Holdings, LLC would acquire the general partner interests of the Partnership. USA Compression Holdings, LLC was formed in November 2010 and its only asset is its investment in the Partnership. This transaction closed on December 23, 2010 and USA Compression Holdings, LLC completed the transaction for cash consideration of approximately $330 million and an exchange of partnership interest in the Partnership with a value of approximately $9 million for Class A units in USA Compression Holdings, LLC. In connection with this change in control, the Partnership’s assets and liabilities were adjusted to fair value on the closing date by application of ‘‘push-down’’ accounting. The Partnership incurred $1,838,121 of acquisition related costs in conjunction with the transactions which are included in selling, general and administrative expenses in the consolidated statement of operations.

As a result of the application of ‘‘push down’’ accounting in connection with the acquisition, the financial statements prior to December 31, 2010 represent the operations of the Predecessor and are not comparable with the financial statements on or after December 31, 2010. References to the ‘‘Successor’’ refer to the Partnership on or after December 31, 2010, after giving effect to ‘‘push down’’ accounting. References to the ‘‘Predecessor’’ refer to the Partnership prior to but excluding December 31, 2010.

The Partnership applied the guidance in Accounting Standards Codification (ASC) 820, Fair Value Measurements and Disclosures (ASC 820), in determining the fair value of partners’ capital, which was based on the purchase of the limited partner and general partner interests in the amount of $338,953,706.

The Partnership then developed the fair value of its assets and liabilities, with the assistance of third-party valuation experts, using the guidance in ASC 820.

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The consolidated financial statements of the Partnership have been prepared in accordance with GAAP and include the accounts of all controlled subsidiaries after the elimination of all intercompany accounts and transactions. The change of control transaction that occurred on December 23, 2010 has been reflected in the consolidated financial statements of the Partnership using, for accounting purposes, a date of convenience of December 31, 2010. The impact of recording the change in control as of December 23, 2010 would not have a material impact on the consolidated financial statements.

Current assets	$	14,564,290
Plant, property and equipment	350,069,378
Identifiable intangible asset — customer relationships	72,000,000
Identifiable intangible asset — trade names	15,600,000
Goodwill	157,075,195
Assets acquired	609,308,863
Current liabilities	18,548,539
Long-term portion of interest rate swaps	1,724,173
Note payable — other	42,527
Note payable — senior debt	250,039,918
Net assets acquired	$	338,953,706

The sale of the Partnership on December 23, 2010, triggered the payment of $4,906,870 of success fees to a broker and $3,906,716 of stock based compensation expense. The Partnership has determined that its accounting policy for any cost that will be triggered by the consummation of a business combination will be to recognize the cost when the business combination is consummated. Accordingly, the broker fees and stock based compensation have not been recorded in the Statement of Operations for the predecessor period since that statement depicts the results of operations just prior to consummation of the transaction. In addition, since the successor period reflects the effects of push-down accounting, these costs have also not been recorded as an expense in the successor period. However, the costs were reflected in the purchase accounting adjustments which were applied in arriving at the opening balances of the successor.

On January 18, 2013, the Partnership completed its initial public offering (“IPO”) pursuant to a Registration Statement on Form S-1, as amended (Reg. No. 333-174803), that was declared effective on January 14, 2013. Under the registration statement, the Partnership sold 11,000,000 common units at a price to the public of $18.00 per common unit, which generated net proceeds to the Partnership of approximately $180.8 million after deducting underwriting discounts and commissions of $12,127,500, structuring fees of $742,500 and offering expenses of $4,344,069. The Partnership used the net proceeds from the offering to repay $180.8 million of indebtedness outstanding under its revolving credit facility.

(2) Summary of Significant Accounting Policies

(a) Cash and Cash Equivalents

Cash and cash equivalents consist of all cash balances. As of December 31, 2012 and 2011, $6,500 and $3,000, respectively, in cash was subject to certain provisions under credit agreements with a financial institution, as more fully described in note 4.

(b) Trade Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts of $259,638 and $260,598 at December 31, 2012 and 2011, respectively, is the Partnership’s best estimate of the amount of probable credit losses in the Partnership’s existing accounts receivable. The Partnership determines the allowance based upon historical write-off experience and specific identification. The Partnership does not have any off-balance-sheet credit exposure related to its customers.

(c) Inventories

Inventories are valued at the lower of cost or market using the first-in, first-out method. Inventory consists of parts used in the assembly of compression units. Purchases of these assets are considered operating activities in the consolidated statement of cash flows.

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(d) Property and Equipment

Property and equipment are carried at cost. Overhauls and major improvements that increase the value or extend the life of compressor units are capitalized and depreciated over 3 to 5 years. Ordinary maintenance and repairs are charged to income. Depreciation is calculated using the straight-line method of accounting over the estimated useful lives of the assets as follows:

Compression equipment		25 years
Furniture and fixtures		7 years
Vehicles and computer equipment		3 - 7 years
Leasehold improvements		5 years

Successor depreciation expense for the years ended December 31, 2012 and 2011 was $38,856,318 and $29,713,779, respectively, and Predecessor depreciation expense for the year ended December 31, 2010 was $24,569,322.

(e) Impairments of Long-Lived Assets

Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written-down to estimated fair value. An asset shall be tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount of the carrying value exceeding the fair value of the asset is recognized. Fair value is generally determined from estimated discounted future net cash flows. The Partnership did not record impairment of long-lived assets in 2012, 2011 or 2010.

(f) Revenue Recognition

Revenue from compression service and equipment rental operations is recorded when earned over the period of service, rental and maintenance contracts, which generally range from one month to five years. Parts and service revenue is recorded as parts are delivered or services are performed for the customer.

(g) Income Taxes

The Partnership elected to be treated under SubChapter K of the Internal Revenue Code. Under SubChapter K, a partnership return is filed annually reflecting each partner’s share of the partnership’s income or loss. Therefore, no provision has been made for federal income tax. Partnership net income (loss) is allocated to the partners in proportion to their respective interest in the Partnership.

As a partnership, all income, gains, losses, expenses, deductions and tax credits generated by the Partnership generally flow through to its unitholders. However, Texas imposes an entity-level income tax on partnerships.

The State of Texas’ margin tax became effective for tax reports originally due on or after January 1, 2008. This margin tax requires partnerships and other forms of legal entities to pay a tax of 1.0% on its ‘‘margin,’’ as defined in the law, based on 2012, 2011 and 2010 results. The margin tax base to which the tax rate will be applied is either the lesser of 70% of total revenues for federal income tax purposes or total revenue less cost of goods sold or compensation for federal income tax purposes. For the years ended December 31, 2012, 2011 and 2010, the Partnership recorded an expense related to the Texas margin tax of $196,040, $154,872 and $155,179, respectively.

Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority. Interest and penalties related to unrecognized tax benefits are included in income tax expense.

(h) Fair Value Hierarchy

Accounting standards on fair-value measurement establish a framework for measuring fair value and stipulate disclosures about fair-value measurements. The standards apply to recurring and nonrecurring financial and non-financial assets and liabilities that

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require or permit fair-value measurements. A new accounting standard became effective for the Partnership on January 1, 2008, for all financial assets and liabilities and recurring non-financial assets and liabilities. On January 1, 2009, the standard became effective for non-recurring non-financial assets and liabilities. Among the required disclosures is the fair-value hierarchy of inputs the Partnership uses to value an asset or a liability. The three levels of the fair-value hierarchy are described as follows:

Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the Partnership has the ability to access at the measurement date.

Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.

Level 3 inputs are unobservable inputs for the asset or liability.

At December 31, 2012 and 2011, the only financial assets and liabilities measured at fair value in the Partnership’s consolidated balance sheet on a recurring basis are its interest rate swaps. The following table presents assets and liabilities that are measured at fair value on a recurring basis (including items that are required to be measured at fair value and items for which the fair value option has been elected) at December 31, 2012 and 2011:

	December 31,		Quoted prices in active markets for identical assets (Level 1)	Significant other observable inputs (Level 2)	Significant unobservable inputs (Level 3)
Liabilities:
Interest rate derivatives — 2012	$	—	—	—	—
Interest rate derivatives — 2011	$	2,180,049	—	2,180,049	—

The Partnership considers any transfers between levels within the fair value hierarchy to have occurred at the beginning of a quarterly reporting period. The Partnership did not recognize any transfers between Level 1, Level 2 or Level 3 of the fair value hierarchy and did not change its valuation techniques or inputs during the year ended December 31, 2012.

(i) Fair Value of Financial Instruments

The Partnership’s financial instruments consist primarily of cash and cash equivalents, trade accounts receivable, trade accounts payable, notes payable and interest rate swap arrangements. The book values of cash and cash equivalents, trade accounts receivable, and trade accounts payable are representative of fair value due to their short-term maturity. The carrying amounts of notes payable approximates fair value based on the interest rates charged on instruments with similar terms and risks. The carrying amounts of interest rate swap arrangements are based on valuation models prepared by the derivatives issuer which are intended to approximate current market values. For derivatives accounted for as cash flow hedges, the Partnership also assesses, both at inception and on an ongoing basis, whether the hedging transactions are highly effective in offsetting cash flows of the hedged item. Changes in the fair value of the highly effective portion of the derivative are recognized in other comprehensive income on the balance sheet. The ineffective portion of the change in fair value of the derivative is reported in earnings.

(j) Pass Through Taxes

Taxes incurred on behalf of, and passed through to customers are accounted for on a net basis.

(k) Use of Estimates

The preparation of the consolidated financial statements of the Partnership in conformity with accounting principles generally accepted in the United States of America requires the management of the Partnership to make estimates and assumptions that affect the amounts reported in these consolidated financial statements and the accompanying results. Actual results could differ from these estimates.

(l) Intangible Assets

As of December 31, 2012, intangible assets consisted of the following:

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	December 31, 2012					December 31, 2011
	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
Customer relationships	$	72,000,000	$	(4,800,000	)	$	72,000,000	$	(2,400,000	)
Trade names	15,600,000		(1,248,000		)	15,600,000		(624,000		)
Intangible assets	$	87,600,000	$	(6,048,000	)	$	87,600,000	$	(3,024,000	)

Intangible assets are amortized on a straight line basis over their estimated useful lives, which is the period over which the assets are expected to contribute directly or indirectly to the Partnership’s future cash flows. The estimated useful lives range from 25 to 30 years. The expected amortization of the intangible assets for each of the five succeeding years is as follows:

Year ending December 31,	Total
2013	$	3,024,000
2014	3,024,000
2015	3,024,000
2016	3,024,000
2017	3,024,000

The Partnership assesses long-lived assets, including intangible assets, for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is assessed by comparing the carrying amount of an asset to undiscounted future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured as the amount by which the carrying amounts exceed the fair value of the assets. The Partnership did not record any impairment of intangible assets in 2012.

(m) Goodwill

Goodwill represents the excess of the purchase price over the fair value of identifiable net assets upon the change in control on December 23, 2010. Goodwill is not amortized, but is tested 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.

Because quoted market prices for the Partnership’s reporting unit are not available as of October 1, 2012, management must apply judgment in determining if it is more likely than not that the fair value of the reporting unit is less than its carrying amount for purposes of performing the optional qualitative assessment for the annual goodwill impairment test. Management uses all available information to make these determinations, including evaluating the macroeconomic environment and industry specific conditions at the assessment date of October 1, 2012.

As a result of the qualitative assessment, the Partnership has determined that it is not more likely than not that the fair value of the reporting unit is less than its carrying amount. The Partnership did not record any impairment of goodwill for the years ended December 31, 2012 and 2011.

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(3) Property and Equipment

Property and equipment consisted of the following at December 31:

	2012			2011
Compression equipment	$	666,811,135		$	478,596,628
Furniture and fixtures	438,556			439,514
Automobiles and vehicles	7,587,725			5,640,430
Computer equipment	3,206,311			1,523,150
Leasehold improvements	97,623			53,076
Total	678,141,350			486,252,798
Less accumulated depreciation and amortization	(68,011,640		)	(29,604,193		)
Total	$	610,129,710		$	456,648,605

In 2011, the Partnership had leased compressor units with certain purchase options as more fully described in note 8. The Partnership has no compressor units with material customer lease/ purchase options as of December 31, 2012. On December 16, 2011, the Partnership entered into an agreement with a compression equipment supplier to reduce certain previously made progress payments from $10 million to $2 million. The Partnership applied this $8 million credit to new compression unit purchases from this supplier in the first quarter of 2012. The $8 million prepayment is included in Other Assets on the balance sheet at December 31, 2011.

As of December 31, 2012 and 2011, there is $5,940,149 and $4,002,511, respectively, of property and equipment purchases in accounts payable and accrued liabilities.

(4) Long-Term Debt

The long-term debt of the Partnership consisted of the following at December 31:

	2012		2011
Senior debt	$	502,266,210	$	363,773,468
Various other notes	—		39,067
Total debt	502,266,210		363,812,535
Less current debt	—		39,067
Long-term debt	$	502,266,210	$	363,773,468

(a) Senior Debt

On December 23, 2010, the Partnership entered into a Third Amended and Restated Credit Agreement. Borrowing availability under this senior debt facility is limited to the lesser of the $400,000,000 committed facility amount and a borrowing base defined in the credit agreement. The senior debt facility is evidenced by notes issued to each of several lenders named in the credit agreement, is secured by a first priority lien against the assets of the Partnership and matures on October 5, 2015. Interest on debt issued under the facility is due and payable in arrears and calculated, at the option of the Partnership, on either a floating rate basis, payable monthly or a LIBOR basis, payable at the end of the applicable LIBOR period (1, 2, 3, or 6 months), but no less frequently than quarterly. LIBOR borrowings bear interest at LIBOR for the applicable period plus a margin of 3.00% to 3.75% based on the leverage ratio of the Partnership’s amount outstanding under this facility to consolidated EBITDA (earnings before interest, taxes, depreciation and amortization) as defined in the credit agreement. Floating rate borrowings bear interest at a rate per annum that is the higher of bank prime rate or the federal funds rate plus 0.50%, without additional margin. Generally, the Partnership maintains several tranches of LIBOR and floating rate borrowings at any time. In addition, the Partnership pays an annual administration fee and an unused commitment fee of 0.50%. The $400,000,000 facility includes a $20,000,000 sub-line for issuing letters of credit for a fee at a per annum rate equal to the margin for LIBOR borrowings on the average daily undrawn stated amount of each letter of credit issued under the facility. The Partnership paid various loan fees and incurred costs in respect of the Third Amended and Restated Credit Agreement in the amount of $5,059,781 in 2010.

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On June 6, 2011, the Partnership made a first amendment to the credit agreement converting each reference to “USA Compression Holdings, LP” to “USA Compression Partners, LP.” Additionally, each reference to USA Compression Holdings, LP as a “Texas limited partnership” in the credit agreement or any other loan document shall now mean a reference to USA Compression Partners, LP as a “Delaware limited partnership.”

On November 16, 2011, the Partnership made a second amendment to the credit agreement whereby the aggregate commitment under the facility increased from $400 million to $500 million and reduced the applicable margin for LIBOR loans to a range of 200 to 275 basis points above LIBOR, depending on the Partnership’s leverage ratio. In addition, the unused commitment fee was reduced to 0.375%.

On June 1, 2012, the Partnership made a third amendment to the credit agreement whereby the aggregate commitment under the facility increase from $500 million to $600 million. In addition, on June 1, 2012, the Partnership entered into the Fourth Amended and Restated Credit Agreement in order to provide a covenant structure that is more appropriate for a public company than was the prior credit agreement, including a reduction of the applicable margin for LIBOR loans to a range of 175 to 250 basis points above LIBOR, depending on the Partnership’s leverage ratio. This amended and restated credit agreement became effective on January 18, 2013, the closing date of the Partnership’s initial public offering. On December 10, 2012, the Partnership amended the Fourth Amended and Restated Credit Agreement to extend the periods during which the maximum funded debt to EBITDA ratio thresholds will apply. In addition, borrowing availability under the revolving credit facility was linked to the Partnership’s asset base, with the increased maximum capacity of $600,000,000 (subject to a further potential increase of $50,000,000). The revolving credit facility is secured by a first priority lien against the Partnership’s assets and matures on October 5, 2015, at which point all amounts outstanding will become due.

As of December 31, 2012, the credit agreement contained various financial, negative and affirmative covenants, including covenants requiring the Partnership to maintain minimum ratios of consolidated cash flow to consolidated fixed charges and a maximum funded debt to EBITDA ratio. In addition, this agreement limited or restricted the Partnership’s ability to incur other debt, create liens and make investments, enter transactions with affiliates and undertake certain fundamental changes, including merger and consolidation, sale of all or substantially all assets, dissolution and liquidation. As of December 31, 2012 and 2011, the Partnership was in compliance with all of the covenants under the current credit agreement.

The Fourth Amended and Restated Credit Agreement permits us to make distributions of available cash to unitholders so long as (a) no default or event of default under the facility occurs or would result from the distribution, (b) immediately prior to and after giving effect to such distribution, the Partnership is in compliance with the facility’s financial covenants and (c) immediately after giving effect to such distribution, the Partnership has availability under the revolving credit facility of at least $20,000,000. In addition, the amended and restated credit agreement contains various covenants that may limit, among other things, the Partnership’s ability to:

· grant liens;

· make certain loans or investments;

· incur additional indebtedness or guarantee other indebtedness;

· subject to exceptions, enter into transactions with affiliates;

· sell the Partnership’s assets; or

· acquire additional assets.

The Fourth Amended and Restated Credit Agreement also contains financial covenants requiring the Partnership to maintain:

· a minimum EBITDA to interest coverage ratio of 2.5 to 1.0; and

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quarter ending June 30, 2014 and each fiscal quarter thereafter, in each case subject to a provision for increases to such thresholds by 0.5 in connection with certain future acquisitions for the six consecutive month period following the period in which any such acquisition occurs.

If an event of default exists under the revolving credit facility, the lenders will be able to accelerate the maturity of the revolving credit facility and exercise other rights and remedies.

The Partnership paid various loan fees and incurred costs in respect of the third amendment to the credit agreement and the Fourth Amended and Restated Credit Agreement in the amount of $1,805,183 in 2012 which were capitalized to loan costs and will be amortized through October 2015.

At December 31, 2012, borrowing availability under the revolving credit facility was $91,196,544. The borrowing base consists of eligible accounts receivable, inventory and compression units. The largest component, representing 96% of the borrowing base at December 31, 2012 and 2011, is eligible compression units—compressor packages that are leased, rented or under service contracts to customers and carried in the financial statements as fixed assets. The Partnership’s effective interest rate in effect for all borrowings under its revolving credit facility at December 31, 2012 and 2011, respectively, as adjusted by the interest rate swap referred to in note 4(b) below, was 2.96% and 5.55%, respectively. There were no letters of credit issued at December 31, 2012 and 2011.

The senior debt facility expires in 2015 and the Partnership expects to maintain its facility for the term. The facility is a ‘‘revolving credit facility’’ that includes a ‘‘springing’’ lock box arrangement, whereby remittances from customers are forwarded to a bank account controlled by the Partnership, and the Partnership is not required to use such remittances to reduce borrowings under the facility, unless there is a default or excess availability under the facility is reduced below $20,000,000. As the remittances do not automatically reduce the debt outstanding absent the occurrence of a default or a reduction in excess availability below $20,000,000, the debt has been classified as long-term at December 31, 2012 and 2011.

Maturities of long term debt:

Year ending December 31
2013	—
2014	—
2015	502,266,210
2016	—
	$	502,266,210

On January 18, 2013, the Partnership completed its IPO pursuant to a Registration Statement on Form S-1, as amended (Reg. No. 333-174803), and used the net proceeds from the offering to repay $180,785,931 of indebtedness outstanding under its revolving credit facility.

(b) Hedging and Use of Derivative Instruments

The Partnership has only limited involvement with derivative financial instruments and uses them principally to manage well-defined interest rate risk. Interest rate swap agreements are used to reduce the potential impact of fluctuations in interest rates on variable rate long-term debt. The swaps are not used for trading or speculative purposes.

In November 2008, the Partnership entered into an interest rate swap agreement expiring October 5, 2012 for a notional amount of $75,000,000. The fair value of the interest rate swap was recorded on the balance sheet as a liability of $1,559,198 at December 31, 2011.

In May 2009, the Partnership entered into an interest rate swap agreement expiring June 1, 2012 for a notional amount of $35,000,000. The fair value of this interest rate swap was recorded on the balance sheet as a liability of $277,923 at December 31, 2011. In August 2009, the Partnership entered into an interest rate swap agreement expiring August 1, 2012 for a notional amount of $30,000,000. The fair value of this interest rate swap was recorded on the balance sheet as a liability of $342,928 at December 31, 2011.

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These swap agreements qualified for hedge accounting and were assumed to be perfectly effective prior to the change in control on December 23, 2010, and thus, there was no ineffectiveness to be recorded in earnings. During 2010, $1,694,161 representing the changes in the fair value of the highly effective portion of the derivative, were recognized in accumulated other comprehensive income. As of December 31, 2011, the Partnership did not designate these interest rate swaps as cash flow hedges.

The swap agreements entitled the Partnership to pay or receive from the counter-party, monthly, the amount by which the counter-party’s variable rate (reset monthly) was less than or exceeded the Partnership’s fixed rate under the agreements. Under the swaps, the Partnership exchanged fixed rates of 3%, 1.9% and 2.055% on the notional amounts of $75,000,000, $35,000,000 and $30,000,000, respectively, for a floating rate tied to the BBA London Interbank Offering Rate (LIBOR). The swaps minimized interest rate exposure on the revolving senior debt facility, and in effect, converted variable interest payments on the aggregate notional amount to fixed interest payments. Amounts paid or received from the interest rate swap were charged or credited to interest expense and matched with the cash flow and interest expense of the senior debt being hedged, resulting in an adjustment to the effective interest rate. The swap payments (receipts) for the years ended December 31, 2012, 2011 and 2010 were $2,313,803, $3,254,047 and $3,196,806, respectively. As of December 23, 2010, the interest rate swaps were recorded at fair value, and unrealized losses previously recorded in accumulated other comprehensive income related to the instruments, were eliminated. During 2012 and 2011, interest expense was reduced by $2,180,049 and $2,628,523, respectively, due to changes in fair value of the interest rate swaps.

(5) Restructuring Charges

During the year ended December 31, 2011, the Partnership incurred $300,000 of restructuring charges for severance and retention benefits related to the termination of certain administrative employees. These charges are reflected as restructuring charges in our consolidated statement of operations. We paid these restructuring charges in 2012.

(6) Share-Based Compensation

Prior to the sale of the Partnership on December 23, 2010 (see note 1), the Partnership had reserved certain partnership interest units as an incentive pool for issuance to its employees or other parties. The awards issued in 2011, 2010 and 2009 under this incentive pool are as follows:

	Total units reserved	Class C interest units
	under incentive pool	Grant date fair value per unit		Vested		Unvested		Share based compensation expense
Balance of awards as of December 31, 2009	5,413,505			4,245,136		4,171,704
Expense recorded in 2009								$	165,839
Issuance of capital interest units	200,000	$	1.22	—		200,000		$	81,400
Vesting	—			4,371,704		(4,371,704	)	198,006
Settlement of profits interests	5,213,505			(8,616,840	)	—		—
Forfeitures	—			—		—		—
Balance of awards as of December 31, 2010	—			—		—
Expense recorded in 2010								$	279,406

Generally, partnership interest unit awards that have vesting contingent on future service conditions are amortized over their applicable vesting period using the straight-line method. For nonvested share awards subject to service and performance conditions, the Partnership is required to assess the probability that such performance conditions will be met. If the likelihood of the performance condition being met is deemed probable, the Partnership will recognize the expense using the straight-line attribution method. The Partnership recognized $110,000 of share based compensation expense for the change in value of vested units granted to one of its officers during 2010. Upon their change in control, all of the profits interests vested and were settled for $3,868,118.

The Partnership granted certain Class C common interests to two existing Special Limited Partners in 2006. The Partnership did not record any expense related to these awards in 2006 as it was determined that it was not probable that the performance conditions would be met. In June 2007, these Class C common interest awards were modified. The Special Limited Partners exchanged their 0.7% Class C common interest awards for 901,501 Class B units. These units were all unvested at December 31,

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2009, and fully vest on March 31, 2016. Due to this modification and as the Partnership had determined that it is probable that the future service condition will be met, share-based compensation expense for the fair value on the date of the modification over the period July 2007 to December 2010 was recorded. The awards to these two Special Limited Partners fully vested upon the change of control that occurred on December 23, 2010. The amount of share-based compensation expense related to the modified awards was $103,029 in 2010 and 2009.

Fair value of these awards was based on third party valuations of enterprise value of the Partnership. These awards were fully vested and terminated with the sale of Holdings as described in note 1.

During 2010 and 2011, USA Compression Holdings, LLC issued to certain employees and members of its management Class B nonvoting units. These Class B units are liability-classified profits interest awards which have a service condition.

The Class B units are entitled to a cash payment of 10% of net proceeds primarily from a monetization event, as defined under the provisions related to these Class B unit awards, in excess of USA Compression Holdings, LLC’s Class A unitholder’s capital contributions and an 8% cumulative annual dividend (both of which are due upon a monetization event) to the extent of vested units over total units of the respective class. Each holder of Class B units is then allocated their pro-rata share of the respective class of unit’s entitlement based on the number of units held over the total number of units in that class of units. The Class B units vest 25% on the first anniversary date of the grant date and then 25% on each successive anniversary for the next three years (pro-rated by month) subject to certain continued employment. Half of the annual vesting automatically is achieved for certain Class B unitholders when USA Compression Holdings, LLC, or one of its subsidiaries, achieves a defined performance target related to a public offering of securities. The units have no expiry date provided the employee remains employed with USA Compression Holdings, LLC or one of its subsidiaries.

	Class B Interest Units
	Grant date fair value per unit		Vested	Unvested		Share based compensation expense
Issuance of profit interest units	$	—	—	1,000,000
Vesting			—	—
Forfeitures			—	—
Balance of awards as of December 31, 2010			—	1,000,000
Expense recorded in 2010						$	—
Issuance of profit interest units	$	—	—	187,500
Vesting			250,000	(250,000	)
Forfeitures			—	—
Balance of awards as of December 31, 2011			250,000	937,500
Expense recorded in 2011						$	—
Issuance of profit interest units	$	—	—	—
Vesting			296,875	(296,875	)
Forfeitures			—	—
Balance of awards as of December 31, 2012			546,875	640,625
Expense recorded in 2012						$	—

Fair value of the Class B units is based on enterprise value calculated by a predetermined formula. As of December 31, 2012, no compensation expense or liability has been recorded related to these Class B units.

The Partnership’s IPO constituted a qualified public offering for purposes of certain vesting provisions of the employee holder’s Class B Units, which resulted in 50% of certain employee’s unvested Class B Units vesting and, if such employee’s employment is terminated by the Partnership’s general partner without cause or the employee resigns for good reason, the remaining unvested Class B Units will vest in full. As used in the Holdings Operating Agreement, “good reason” and “cause” have the meanings set forth in each employee’s employment agreement.

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(7) Transactions with Related Parties

For the year ended December 31, 2012, the Partnership incurred $1,000,000 of expenses related to a management fee under an agreement between USA Compression Holdings, LLC and certain of its affiliates. In connection with the completion of its initial public offering, the Partnership will no longer pay management fees under this agreement.

On June 8, 2011, the Partnership received repayment for a loan made to an officer of $185,631.

William Shea, who has served as a director of USA Compression GP, LLC since June 2011, is currently a director and the chief executive officer of the general partner of Penn Virginia Resource Partners, L.P., or PVR. In 2008, PVR acquired the business of one of the Partnership’s compression services customers and, after such acquisition, has continued to purchase compression services from the Partnership. For the years ended December 31, 2012 and 2011, subsidiaries of PVR made compression services payments to us of approximately $2.2 million and $1.3 million, respectively.

(8) Recent Accounting Pronouncements

In September 2011, the FASB issued an update allowing entities to use a qualitative approach to test goodwill for impairment. Under this update, entities are permitted to first perform a qualitative assessment to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying value. If it is concluded that this is the case, it is necessary to perform the currently prescribed two-step goodwill impairment test. Otherwise, the two-step goodwill impairment test is not required. This update is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. Early adoption is permitted. The Partnership adopted this authoritative guidance in October 2011. The adoption of this new guidance did not have a material impact on the Partnership’s consolidated financial statements.

(9) Commitments and Contingencies

(a) Operating Leases

Rent expense for office space, warehouse facilities and certain corporate equipment for the years ended December 31, 2012, 2011 and 2010 was $1,170,174, $783,800 and $678,428, respectively. Commitments for future minimum lease payments for non-cancelable leases are as follows:

2013	$	816,254
2014	776,858
2015	719,694
2016	725,420
2017	703,774
Thereafter	376,766
	$	4,118,766

(b) Operating Lease Facility

On August 4, 2009, the Partnership entered into an operating lease facility with Caterpillar Financial Services Corporation (CFSC), whereby the Partnership had the ability to lease compression equipment with an aggregate value of up to $45,000,000. The Partnership paid commitment and arrangement fees of $200,000. As part of the facility, the Partnership would pay 150bps, amended December 23, 2010 to 220bps, on the value of the equipment for each lease as funded. The facility was available for leases with inception dates up to and including June 30, 2011, subject to renewals at the discretion of CFSC, and mitigates the need to use available capacity under the existing senior debt facility. Each compressor leased under this facility had a lease term of one hundred twenty (120) months with a buyout option of 25% of cost which approximates fair value at the end of the lease term. At the end of the lease term, the Partnership also had an option to extend the lease term for an additional period of sixty (60) months at an adjusted rate equal to the fair market rate at the time. In the event the Partnership elected not to exercise the buyout or renewal option, the equipment was to be returned in a manner fit for use at the end of the lease term. In addition to the fair value buyout option at the end of the lease term, early buyout option provisions existed at month sixty (60) and at month eighty four (84) of the one hundred twenty (120) month lease term.

F-17

Table of Contents

On December 15, 2011, the Partnership purchased all the compression units previously leased from CFSC for $43 million and terminated all the lease schedules and covenants under the facility. This purchase was funded by additional borrowings under the revolving credit facility. Lease expense under the terms of the facility for the years ended December 31, 2011 and 2010 was $4,053,217 and $2,285,412, respectively. There are no commitments for future minimum lease payments as the lease schedules have been terminated.

(c) Major Customers

The Partnership had revenue from three customers representing 14.5%, 9.4% and 6.4% of total revenue for the year ended December 31, 2012, revenue from three customers representing 15.9%, 9.2% and 4.4% of total revenue for the year ended December 31, 2011, and revenue from two customers representing 18.7% and 6.7% of total revenues for the year ended December 31, 2010.

(d) Litigation

The Partnership may be involved in various claims and litigation arising in the ordinary course of business. In management’s opinion, the resolution of such matters is not expected to have a material adverse effect on the Partnership’s consolidated financial position, results of operations, or cash flows.

(10) Selected Quarterly Financial Data (Unaudited)

In the opinion of the Partnership’s management, the summarized quarterly financial data below (in thousands, except per unit amounts) contains all appropriate adjustments, all of which are normally recurring adjustments, considered necessary to present fairly the Partnership’s financial position and the results of operations for the respective periods.

	March 31, 2012		June 30, 2012		September 30, 2012		December 31, 2012
Revenue	$	27,124	$	28,870	$	31,021	$	31,771
Gross profit (1)	18,103		19,748		21,237		21,903
Net income	1,243		997		1,316		948
Net income allocated to general partner	12		10		13		10
Net income available for limited partners	1,231		987		1,303		938

	March 31, 2011		June 30, 2011			September 30, 2011			December 31, 2011
Revenue	$	23,496	$	23,158		$	23,673		$	28,394
Gross profit	14,555		13,781			13,933			16,846
Net income (loss)	535		(252		)	(234		)	21
Net income (loss) allocated to general partner	5		(3		)	(2		)	0
Net income (loss) available for limited partners	530		(249		)	(232		)	21

(1) Gross profit is defined as revenue less cost of operations, exclusive of depreciation and amortization expense.

(11) Subsequent Events

(a) Initial Public Offering

On January 18, 2013, the Partnership completed its IPO pursuant to a Registration Statement on Form S-1, as amended (Reg. No. 333-174803), that was declared effective on January 14, 2013. Under the registration statement, the Partnership sold 11,000,000 common units at a price to the public of $18.00 per common unit, which generated net proceeds to the Partnership of $180,785,931 after deducting underwriting discounts and commissions of $12,127,500, structuring fees of $742,500 and offering expenses of $4,344,069. The Partnership used the net proceeds from the offering to repay $180,785,931 of indebtedness outstanding under its revolving credit facility.

F-18

PART I		1
Item 1.	Business	1
Item 1A.	Risk Factors	10
Item 1B.	Unresolved Staff Comments	28
Item 2.	Properties	28
Item 3.	Legal Proceedings	28
Item 4.	Mine Safety Disclosures	28
PART II		28
Item 5.	Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	28
Item 6.	Selected Financial Data	31
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	48
Item 8.	Financial Statements and Supplementary Data	49
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	49
Item 9A.	Controls and Procedures	49
Item 9B.	Other Information	49
PART III		49
Item 10.	Directors, Executive Officers and Corporate Governance	49
Item 11.	Executive Compensation	54
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	61
Item 13.	Certain Relationships and Related Transactions, and Director Independence	63
Item 14.	Principal Accountant Fees and Services	65
PART IV		66
Item 15.	Exhibits and Financial Statement Schedules	66

Report of Independent Registered Public Accounting Firm	F-1
Consolidated Balance Sheets as of December 31, 2012 and 2011	F-2
Consolidated Statements of Operations for the years ended December 31, 2012, 2011 and 2010	F-3
Consolidated Statements of Comprehensive Income for the years ended December 31, 2012, 2011 and 2010	F-4
Consolidated Statements of Changes in Partners’ Capital for the years ended December 31, 2012, 2011 and 2010	F-5
Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010	F-6
Notes to Consolidated Financial Statements	F-7