USA Compression Partners, LP - Annual Report: 2014 (Form 10-K)

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-K

 

(Mark One)

 

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

 

For the fiscal year ended December 31, 2014

 

or

 

☐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)

 

 

 

 

(512) 473-2662

(Registrant’s telephone number, including area code)

 

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

 

 

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 ☐    No ☒

 

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 ☐    No ☒

 

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 ☒    No ☐

 

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 ☒    No ☐

 

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.  ☒

 

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.

 

 

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

 

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 of 5% or more of the common units outstanding, for this purpose, as if they were affiliates of the registrant) as of June 30, 2014, the last business day of the registrant’s most recently completed second fiscal quarter was $425,597,152. This calculation does not reflect a determination that such persons are affiliates for any other purpose.

 

As of February 17, 2015, there were 32,036,276 common units and 14,048,588 subordinated units outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE: NONE

 

 

 

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Table of Contents

 

 

 

 

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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”). Important factors that could cause our actual results to differ materially from the expectations reflected in these forward-looking statements include, among other things:

 

 

 

 

 

 

 

 

 

 

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.

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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”) and USAC OpCo 2, LLC (“OpCo 2” and together with USAC Operating, the “Operating Subsidiaries”). References to our “general partner” refer to USA Compression GP, LLC. References to “USA Compression Holdings” refer to USA Compression Holdings, LLC, the owner of our general partner. References to “USAC Management” refer to USA Compression Management Services, LLC, a wholly owned subsidiary of 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.

 

Overview

 

We are a growth oriented Delaware limited partnership and we believe that we are one of the largest independent providers of compression services in the U.S. in terms of total compression fleet horsepower. We have been providing compression services since 1998 and completed our initial public offering in January 2013. As of December 31, 2014, we had 1,549,020 horsepower in our fleet and approximately 230,000 horsepower on order for expected delivery primarily in the first three quarters of 2015.  We provide compression services to our customers primarily in connection with infrastructure applications, including both allowing for the processing and transportation of natural gas through the domestic pipeline system and enhancing crude oil production through artificial lift processes. As such, our compression services play a critical role in the production, processing and transportation of both natural gas and crude oil.

 

We provide compression services in a number of shale plays throughout the U.S., including the Utica, Marcellus, Permian Basin, Eagle Ford, Mississippi Lime, Granite Wash, Woodford, Barnett, Haynesville and Fayetteville shales. The demand for our services is driven by the domestic production of natural gas and crude oil; as such, we have focused our activities in areas of attractive production growth, which are generally found in these shale and unconventional resource plays.  According to recent studies promulgated by the Energy Information Agency (“EIA”), the production and transportation volumes in these plays are expected to increase over time due to the comparatively attractive economic returns versus returns achieved in many conventional basins. Furthermore, the changes in production volumes and pressures of shale plays over time require a wider range of compression services than in conventional basins. We believe the flexibility of our compression units positions us well to meet these changing operating conditions. Our business focuses largely on compression services at infrastructure installations, including centralized natural gas gathering systems and processing facilities, utilizing large horsepower compression units, typically in shale plays; however, we also provide compression services in more mature conventional basins, including crude oil wells targeted by horizontal drilling techniques. The recent advent of horizontal drilling has allowed producers to produce incremental volumes of crude oil on economic terms that tend to remain attractive even in periods of low commodity prices. 

 

We operate a modern fleet of compression units, with an average age of approximately four years. We acquire our compression units from third-party fabricators who build the units to our specifications, utilizing specific original equipment manufacturers and assembling the units in a manner that provides us the ability to meet certain operating condition thresholds. Our standard new-build compression units are generally configured for multiple compression stages allowing us to operate our units across a broad range of operating conditions. The design flexibility of our units, particularly in midstream applications, 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.

 

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’ changing compression requirements. By focusing on the needs of our customers and by providing them with reliable and flexible compression services in geographic areas of attractive growth, we are able to generate stable cash flows for our unitholders.

 

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We provide compression services to our customers under fixed-fee contracts with initial contract terms between six months and five years, depending on the application and location of the compression unit. We typically continue to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. We primarily enter into take-or-pay contracts whereby our customers are required to pay our monthly fee even during periods of limited or disrupted throughput, which enhances the stability and predictability of our cash flows. We are not directly exposed to commodity 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.

 

Our assets and operations are organized into a single reportable segment and are all located and conducted in the United States. See our consolidated financial statements, and the notes thereto, included elsewhere in this report for financial information on our operations and assets; such information is incorporated herein by reference.

 

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:

 

 

 

 

 

 

Our Operations

 

Compression Services

 

We provide compression services for a monthly service fee. As part of our services, we engineer, design, operate, service and repair our fleet of compression units and maintain related support inventory and equipment. We have consistently provided average service run times above the levels required by our customers. In general, our team of field service technicians service only our compression fleet. In limited circumstances for established customers, we will agree to service third-party owned equipment. We seek to enter into service contracts with each of our customers. On August 30, 2013, we completed the acquisition of assets and certain liabilities related to S&R Compression, LLC’s (“S&R”) business of providing gas lift compression services to third parties engaged in the exploration, production, gathering, processing, transportation or distribution of oil and gas in exchange for 7,425,261 common units, which were valued at $181.9 million at the time of issuance (the “S&R Acquisition”). In connection with the S&R Acquisition, we acquired contracts styled as rentals related to the active compressors in the acquired fleet. We have converted all but a small minority of these agreements into service contracts. We do not own any compression fabrication facilities.

 

Our Compression Fleet

 

The fleet of compression units that we own and use to provide compression services consists of specially engineered compression units that utilize standardized components, principally engines manufactured by Caterpillar, Inc. and compressor frames and cylinders manufactured by Ariel Corporation. Our units can be rapidly and cost effectively modified for specific customer applications. Approximately 97% of our fleet horsepower as of December 31, 2014 was purchased new and the average age of our compression units was approximately four years. Our modern, standardized compressor fleet primarily consists of the Caterpillar 3400, 3500 and 3600 engine classes, which range from 401 to 4,735 horsepower per unit. These larger horsepower units, defined as 400 horsepower per unit or greater, represented 78.3% of our total fleet horsepower (including compression units on order) as of December 31, 2014. In addition, a portion of our fleet consists of smaller horsepower units ranging from 30 horsepower to 390 horsepower that are primarily used in gas lift applications. We believe the young age and overall composition of our compressor fleet results in fewer mechanical failures, lower fuel usage (a direct cost savings for our customers), and reduced environmental emissions.

 

The following table provides a summary of our compression units by horsepower as of December 31, 2014 (including additional new compression unit horsepower on order for delivery primarily in the first three quarters of 2015):

 

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

 

 

 

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A growing number of our compression units contained electronic control systems that enable us to monitor the units remotely by satellite or other means to supplement our technicians’ on-site monitoring visits. We intend to continue to selectively add remote monitoring systems to our fleet during 2015. All of 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

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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 down-time.

 

Generally, we expect each of our compression units to undergo a major overhaul between service deployment cycles. The timing of these major overhauls depends on multiple factors, including run time and operating conditions. 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 are able to schedule overhauls in a way to avoid excessive annual maintenance capital expenditures and minimize the revenue impact of down-time.

 

We believe that our customers, by outsourcing their compression requirements, can achieve higher compression runtimes, which translates into increased volumes of either natural gas or crude oil production and therefore increased revenues.  Utilizing our compression services also allows our customers to reduce their operating, maintenance and equipment costs by allowing us to efficiently manage their changing compression needs. In many of our service contracts, we guarantee our customers availability (as described below) 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 have separate contracts for each distinct location for which we will provide compression services.

 

Term and termination. Our contracts typically have an initial term between six months and five years, depending on the application and location of the compression unit. After the expiration of the applicable term, the contract continues on a month-to-month or longer 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 or when we receive notice from the customer of the problem. Down-time due to scheduled maintenance is also excluded from our availability commitment. Our failure to meet a stated availability guarantee may result in a service fee credit to the customer. As a consequence of our availability guarantee, we are incentivized to perform 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 are based. For service contracts that do not have a stated availability guarantee, we work with those customers to ensure that our compression services meet their operational needs.

 

Fees and expenses. Our customers pay a fixed monthly fee for our services. Compression services generally are billed monthly in advance of the service period, except for certain customers, which are billed at the beginning of the service month, and they are generally due 30 days from the date 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. At the customer’s option, we can provide fluids necessary to run the unit to the customer for an additional fee.  We provide such fluids for a substantial majority of the compression units deployed in gas lift applications. We are also reimbursed by our customers for certain ancillary expenses such as trucking and crane operation, 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 specify the specific compression equipment we will use; instead, in consultation with the customer, we determine what equipment is necessary to perform our contractual commitments.

 

Title; Risk of loss. We own all of the compression equipment in our fleet that 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, workers’ 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 needs related to existing services being provided and to determine the customer’s future compression service 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 250 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, 2014 and 2013 was Southwestern Energy Corporation and its subsidiaries (“Southwestern Energy”). Southwestern Energy accounted for 11.6% of our revenue for the year ended December 31, 2014 and 14.3% of our revenue for the year ended December 31, 2013. Our ten largest customers, including Southwestern Energy, accounted for 46% and 49% of our revenue for the years ended December 31, 2014 and 2013, respectively.

 

Suppliers and Service Providers

 

The principal manufacturers of components for our natural gas compression equipment include Caterpillar, Inc., Cummins Inc., and Arrow Engine Company for engines, Air-X-Changers and Air Cooled Exchangers for coolers, and Ariel Corporation, GE Oil & Gas Gemini products and Arrow Engine Company for compressor frames and cylinders. We also rely primarily on four vendors, A G Equipment Company, Alegacy Equipment, LLC, Standard Equipment Corp. and S&R, 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 increase our costs and change the standardized nature of our fleet. We have not experienced any material supply problems to date, although lead-times for new Caterpillar engines and new Ariel compressor frames have in the past been in excess of one year due to increased demand and supply allocations imposed on equipment packagers and end-users. Please read Part I, Item 1A (“Risk Factors — Risks Related to Our Business — 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”).

 

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 historical availability of attractive financing terms from financial institutions and equipment manufacturers has made the purchase of individual compression units increasingly affordable to our

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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. Please read Part I, Item 1A (“Risk Factors — Risks Related to Our Business — We face significant competition that may cause us to lose market share and reduce our cash available for distribution”).

 

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.

 

Insurance

 

We believe that our insurance coverage is customary for the industry and adequate for our business. As is customary in the energy 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, subject to significant deductibles, 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. Please read Part I, Item 1A (“Risk Factors — Risks Related to Our Business — We do not insure against all potential losses and could be seriously harmed by unexpected liabilities”).

 

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 assist customers in obtaining permits or approvals in our operations from various federal, state and local authorities. 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 adversely affect the environment.  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. Please read Part I, Item 1A (“Risk Factors — Risks Related to Our Business — We are subject to substantial environmental regulation, and changes in these regulations could increase our costs or liabilities”).

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Air emissions. The Clean Air Act (“CAA”) and comparable state laws regulate emissions of air pollutants from various industrial sources, including natural gas compressors, and 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 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, in 2010, the U.S. Environmental Protection Agency (“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. In 2012, the EPA proposed amendments to the final rule in response to several petitions for reconsideration, which were finalized and became effective in 2013. The rule requires us to undertake certain expenditures and activities, including purchasing and installing emissions control equipment on certain compressor engines and generators.

 

In 2012, the EPA proposed minor amendments to the CAA regulations applicable to the manufacturers, owners and operators of new, modified and reconstructed stationary reciprocating internal combustion engines, also known as Quad J regulations, in order to conform the final rule to the amendments to the Quad Z regulations discussed above. These amendments were finalized and became effective in 2013. These modifications do not impose material unbudgeted costs on operations.

 

On November 25, 2014, the EPA issued a proposed rule to strengthen the National Ambient Air Quality Standard (“NAAQs”) for ground level ozone. The proposed rule updates both the primary ozone standard and the secondary standard. Both proposed standards are 8-hour standards set within a range of 65 to 70 parts per billion (ppb). The EPA is also seeking comments on levels for the health standard as low as 60 ppb. The EPA will take comments on this proposed regulation for 90 days after its publication in the federal register and has stated it will issue a final decision by October 1, 2015. In addition, in 2013, the EPA promulgated a final rule revising the annual standard for fine particulate matter, or PM 2.5, by lowering the level from 15 to 12 micrograms per cubic meter. On December 18, 2014, the EPA issued final area designations for the 2012 NAAQs for PM 2.5. Designation of new non-attainment areas for the revised ozone or PM 2.5 NAAQS may result in additional federal and state regulatory actions that may impact our customers’ operations and increase the cost of additions to property, plant and equipment.

 

In 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 included New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“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 as well as the first federal air standards for natural gas wells that are hydraulically fractured. In addition, the rules establish leak detection requirements for natural gas processing plants at 500 ppm. In 2013, the EPA issued a final update to the VOC performance standards for storage tanks used in crude oil and natural gas production and transmission. On December 19, 2014, the EPA published final amendments to the July 2014 proposal. 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 may 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 (“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

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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 cash available for distribution.

 

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. In recent years, the U.S. Congress has considered legislation to reduce emissions of greenhouse gases. 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 greenhouse gas emissions issues. However, almost half of the states have begun to address greenhouse gas emissions, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs. Depending on the particular program, we could be required to control greenhouse gas emissions or to purchase and surrender allowances for greenhouse gas emissions resulting from our operations.

 

Independent of Congress, the EPA is beginning to adopt regulations controlling greenhouse gas emissions under its existing CAA authority. For example, on December 15, 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other greenhouse gases endanger 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 restrict emissions of greenhouse gases under existing provisions of the CAA. In 2009, the EPA adopted rules regarding regulation of greenhouse emissions from motor vehicles. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions in the United States beginning in 2011 for emissions occurring in 2010 from specified large greenhouse gas emission sources. On November 30, 2010, the EPA published a final rule expanding its existing greenhouse gas 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 greenhouse gas 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 made certain large stationary sources and modification projects subject to permitting requirements for greenhouse gas emissions under the CAA.

 

Both the Tailoring Rule and the EPA’s endangerment finding were challenged in federal court and were upheld by the D.C. Court of Appeals.  In July 2014, the United States Supreme Court invalidated the Tailoring Rule but it refused to consider other issues such as whether greenhouse gases endanger public health. As a result, under federal law, a source is no longer required to meet the PSD and Title V permitting requirements based solely on its greenhouse gas emissions.

 

Finally, on January 8, 2014, the EPA published standards of performance for greenhouse gas emissions from new power plants. The proposal sets forth a performance standard for integrated gasification combined cycled units and utility boilers based on the use of partial carbon capture and sequestration technology. The proposal also sets limits for stationary natural gas combustion turbines based on the use of natural gas combined cycle technology. Comments on this proposed rule were due March 10, 2014. In addition, on June 2, 2014, the EPA proposed the Clean Power Plan rule, which is intended to reduce carbon emissions from existing power plants. The rule was published in the Federal Register on June 18, 2014. Comments on the plan were due on December 1, 2014 and the EPA is expected to issue a final rule regarding carbon emissions from new power plants sometime in mid-summer 2015. In June 2014, an Ohio-based coal company filed a petition for an extraordinary writ in the United States Court of Appeals in Washington, D.C. challenging the EPA’s authority to regulate carbon dioxide emissions from existing coal-fired power plants under Section 111(d) of the Clean Air Act. Briefing in this case is currently ongoing.

 

Although it is not currently possible to predict with specificity how any proposed or future greenhouse gas legislation or regulation 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

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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 (“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 the majority of our standard natural gas compression contracts for obtaining any discharge permits that may be required under the CWA.

 

Safe Drinking Water Act. A significant 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 (“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, have been proposed and 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 were originally anticipated to be available in 2014, but are now expected in March 2015. The EPA also has 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, including prohibitions on the practice. We cannot predict the future of such legislation and what additional, if any, provisions would be included. 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 (“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 (“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 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.

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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 installed 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 (“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.

 

Employees

 

USAC Management, a wholly owned subsidiary of our general partner, performs certain management and other administrative services for us, such as accounting, corporate development, finance and legal.  All of our employees, including our executive officers, are employees of USAC Management. As of December 31, 2014, USAC Management had 457 full time employees. None of our employees are subject to collective bargaining agreements. We consider our employee relations to be good.

 

Available Information

 

Our internet website address is www.usacpartners.com. We make available, free of charge at the “Investor Relations” portion of our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as soon as reasonably practicable after such reports are electronically filed with, or furnished to, the SEC. The information contained on our website does not constitute part of this report.

 

The SEC maintains an internet website that contains these reports at www.sec.gov. Any materials we file with the SEC also may be read or copied at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. Information concerning the operation of the Public Reference Room may be obtained by calling the SEC at (800) 732-0330.

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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.

 

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 make cash distributions at our current distribution rate to holders of our common units and subordinated units.

 

In order to make cash distributions at our current distribution rate of $0.51 per unit per quarter, or $2.04 per unit per year, we will require available cash of $23.5 million per quarter, or $94.1 million per year, based on the number of common units, subordinated units and the 1.7% general partner interest outstanding as of February 17, 2015. 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:

 

 

 

 

 

 

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

 

 

 

 

 

 

 

 

 

 

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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.

 

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 likely depress the level of production activity and result in a decline in the demand for our compression services, which could result in a reduction in our revenues and our cash available for distribution. Lower natural gas 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, an increasing percentage of natural gas and crude oil production comes from unconventional sources, such as shales, tight sands and coalbeds. Such sources can be less economically feasible to produce in low commodity price environments, in part due to costs related to compression requirements, and a reduction in demand for natural gas or gas lift for crude oil may cause such sources of natural gas or crude oil 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 crude oil or impact the economic feasibility of development of new fields or production of existing fields, which are important components of our ability to expand.

 

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.

 

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, 2014 and 2013 was Southwestern Energy. Southwestern Energy accounted for 11.6% and 14.3% of our revenue for the years ended December 31, 2014 and 2013, respectively. Our ten largest customers, including Southwestern Energy, accounted for  46% and 49% of our revenue for the years ended December 31, 2014 and 2013, 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 cash available for distribution.

 

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, including being unable to access 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. The recent volatility in commodity prices has caused many of our customers to reconsider near-term capital budgets, which may impact large-scale natural gas infrastructure and crude oil production activities. We expect the drop in commodity prices will cause a  delay or cancellation of some customers’ projects. 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 cash available for distribution.

 

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. All of these competitive pressures could have

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a material adverse effect on our business, results of operations, financial condition and reduce our cash available for distribution.

 

Our customers may choose to vertically integrate their operations by purchasing and operating their own compression fleet, expanding the amount of compression units they currently own or using alternative technologies for enhancing crude oil production.

 

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. The historical 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. In addition, there are many technologies available for the artificial enhancement of crude oil production, and our customers may elect to use these alternative technologies instead of the gas lift compression services we provide. Such vertical integration, increases in vertical integration or use of alternative technologies 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 cash available for distribution.

 

A significant portion of our services are provided to customers on a month-to-month basis, and we cannot be sure that such customers will continue to utilize our services.

 

Our contracts typically have an initial term between six months and five years, depending on the application and location of the compression unit. After the expiration of the applicable term, the contract continues on a month-to-month or longer basis until terminated by us or our customers upon notice as provided for in the applicable contract. As of December 31, 2014, approximately 36% of our compression services on a horsepower basis (and 40% on a revenue basis for the year ended December 31, 2014) 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 cash available for distribution.

 

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

 

A principal focus of our strategy is to continue to grow the per unit distribution on our common 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:

 

 

 

 

 

 

 

 

 

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If we do not achieve our expected growth, we may not be able to maintain or increase distributions to our unitholders, in which event the market price of our common units will likely decline materially.

 

We may be unable to grow successfully through 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. On August 30, 2013, we completed the acquisition of all of the compression and related assets of S&R.  We will continue to review acquisition opportunities in the future, but 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 acquisitions successfully 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.

 

Our partnership agreement requires us to distribute to our unitholders all of our available cash, which excludes expenses and prudent operating reserves. We expect that we will rely primarily upon external financing sources, including borrowings under our revolving credit facility and the issuance of 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 ability to increase distributions to our uniholders could be significantly impaired. 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 our cash available for distribution.

 

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

 

We have a $1.1 billion revolving credit facility that matures on January 6, 2020. In addition, we have the option to increase the amount of total commitments under the revolving credit facility by $200 million, subject to receipt of lender commitments and satisfaction of other conditions. As of December 31, 2014, we had outstanding borrowings of $594.9 million, borrowing availability (based on our borrowing base) of $255.1 million and, subject to compliance with the applicable financial covenants, borrowing availability under the revolving credit facility of $133.3 million. Financial covenants permitted a maximum leverage ratio of 5.50 to 1.0 as of December 31, 2014 and will permit a maximum leverage ratio of 5.95 to 1.0 as of March 31, 2015.  As of February 17, 2015, we had outstanding borrowings of $657.4 million. 

 

Our ability to incur additional debt is subject to limitations in our revolving credit facility, including certain financial covenants. Our level of debt could have important consequences to us, including the following:

 

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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 could be impacted by market interest rates, as all of our outstanding borrowings are subject to interest rates that fluctuate with movements in interest rate markets. A substantial increase in the interest rates applicable to our outstanding borrowings could have a material impact on our cash available for distribution. If our operating results are not sufficient to service our current or future indebtedness, we could 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 terms satisfactory to us, 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 revolving credit facility restricts or limits our ability (subject to exceptions) to:

 

 

 

 

 

 

 

 

Furthermore, our revolving credit facility contains certain operating and financial covenants. Our ability to comply with these covenants and restrictions 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 other 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 may be prohibited from making distributions to our unitholders. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. We may not be able to replace such revolving credit facility, or if we are, 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 $208.1 million of goodwill and $82.4 million of other intangible assets as of December 31, 2014. Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets. Generally accepted accounting principles of the United States (“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

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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, 2014 and 2013.

 

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 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 could become more challenging as we grow and to the extent energy industry market conditions are competitive. When general industry conditions are good, as was the case for the years ended December 31, 2014 and 2013, 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 could 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., Cummins Inc. and Arrow Engine Company for engines, Air-X-Changers and Air Cooled Exchangers for coolers, and Ariel Corporation, GE Oil & Gas Gemini products and Arrow Engine Company 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 four vendors, A G Equipment Company, Alegacy Equipment, LLC, Standard Equipment Corp. and S&R, 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.

 

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

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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 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.

 

In our business, we routinely deal with natural gas, oil and other petroleum products at our worksites. 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, if implemented, could result in increased compliance costs.

 

In August 2010, the EPA published new regulations under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocating internal combustion engines. In June, 2012, the EPA proposed amendments to the final rule in response to several petitions for reconsideration, and EPA finalized the proposed amendments in January 2013. The final rule was effective in 2013. The rule requires 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. If we were unable to maintain compliance with the final rule, our business, financial condition, results of operations or cash available for distribution could be impacted.

 

On November 25, 2014, the EPA issued a proposed rule to strengthen the NAAQs for ground level ozone. The proposed rule updates both the primary ozone standard and the secondary standard. Both proposed standards are 8-hour standards set within a range of 65 to 70 parts per billion (ppb). The EPA is also seeking comments on levels for the health standard as low as 60 ppb. The EPA will take comments on this proposed regulation for 90 days after its publication in the federal register and has stated it will issue a final decision by October 1, 2015. In addition, in 2013, the EPA promulgated a final rule revising the annual standard for fine particulate matter, or PM 2.5, by lowering the level from 15 to 12 micrograms per cubic meter. On December 18, 2014, the EPA issued final area designations for the 2012 NAAQs for PM 2.5. Designation of new non-attainment areas for the revised ozone or PM 2.5 NAAQS may result in additional federal and state regulatory actions that may impact our customers’ operations and increase the cost of additions to property, plant and equipment.

 

In 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 included New Source Performance Standards to address emissions of sulfur dioxide and 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 as well as the first federal air standards for natural gas wells that are hydraulically fractured. In addition, the rules establish leak detection requirements for natural gas processing plants at 500 ppm. In 2013, the EPA issued a final update to the VOC performance standards for storage tanks used in crude oil and natural gas production and transmission. On December 19, 2014, the EPA published final amendments to the July 2014 proposal.   These rules may require a number of modifications to our operations, including the installation of new

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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 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 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 cash available for distribution. 

 

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. In recent years, the U.S. Congress has considered legislation to reduce emissions of greenhouse gases. 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 greenhouse gas emissions issues. However, almost half of the states have begun to address greenhouse gas emissions, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs. Depending on the particular program, we could be required to control greenhouse gas emissions or to purchase and surrender allowances for greenhouse gas emissions resulting from our operations.

 

Independent of Congress, the EPA is beginning to adopt regulations controlling greenhouse gas emissions under its existing CAA authority. For example, in December 2009, the EPA officially published its findings that emissions of carbon dioxide, methane, and other greenhouse gases endanger 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 restrict emissions of greenhouse gases under existing provisions of the CAA. In 2009, the EPA adopted rules regarding regulation of greenhouse emissions from motor vehicles. In addition, on September 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions in the United States beginning in 2011 for emissions occurring in 2010 from specified large greenhouse gas emission sources. In November 2010, the EPA published a final rule expanding its existing greenhouse gas 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 in December 2010, requires reporting of greenhouse gas 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 greenhouse gas emissions under the CAA.

 

Both the Tailoring Rule and the EPA’s endangerment finding were challenged in federal court and were upheld by the D.C. Court of Appeals.  In July 2014, the United States Supreme Court invalidated the Tailoring Rule but it refused to consider other issues such as whether greenhouse gases endanger public health.  As a result, under federal law, a source is no longer required to meet the PSD and Title V permitting requirements based solely on its greenhouse gas emissions.

 

Finally, on January 8, 2014, the EPA published standards of performance for greenhouse gas emissions from new power plants. The proposal sets forth a performance standard for integrated gasification combined cycled units and utility boilers based on the use of partial carbon capture and sequestration technology. The proposal also sets limits for

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stationary natural gas combustion turbines based on the use of natural gas combined cycle technology.  In addition, on June 2, 2014, EPA proposed the Clean Power Plan rule, which was intended to reduce carbon emissions from existing power plants. Comments on the plan were due on December 1, 2014 and the EPA is expected to issue a final rule regarding carbon emissions from new power plants in January 2015. On June 18, 2014, an Ohio-based coal company filed a petition for an extraordinary writ in the United States Court of Appeals in Washington, D.C. challenging the EPA’s authority to regulate carbon dioxide emissions from existing coal-fired power plants under Section 111(d) of the Clean Air Act. Briefing in this case is currently ongoing.

 

Although it is not currently possible to predict with specificity how any proposed or future greenhouse gas legislation or regulation 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.

 

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 significant 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 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 past sessions of Congress. The U.S. Congress continues to consider legislation to amend the SDWA. 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 were originally anticipated to be available in 2014, but are now expected in March 2015. The EPA also has 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, including prohibitions on the practice. We cannot predict if additional legislation will be enacted and if so, what its provisions would be. If additional levels of regulation, restriction and permits are 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 for our customers that could reduce demand for our compression services, which could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution.

 

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.

 

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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 crude oil and natural gas supplies and markets for crude oil, 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.

 

In connection with the closing of our initial public offering, we became subject to the public reporting requirements of the Exchange Act. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded partnership. We continue to evaluate the effectiveness of and improve upon our internal controls. 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 (“Section 404”). For example, Section 404(a) requires us, among other things, to review and report annually on the effectiveness of our internal control over financial reporting. We were required to comply with Section 404(a) beginning with our fiscal year ended 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 date we completed our initial public offering, which was in 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 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, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders have no right to elect our general partner or its board of directors. USA Compression Holdings is the sole member of our general partner and has 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 have little ability to remove our general partner. As a result of these limitations, the price of our common units may be diminished because of the absence or reduction of a takeover premium in the trading price. Furthermore, 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.

 

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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:

 

 

 

 

 

 

 

 

 

 

 

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Our general partner’s liability regarding our obligations is limited.

 

Our general partner has included, and will continue to include, provisions in its and our contractual arrangements that limit its liability under such 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.

 

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:

 

 

 

 

 

 

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

 

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Even if holders of our common units are dissatisfied, they currently 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 42.0% 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 our 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 in our partnership agreement 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. Generally, poor management of our business by our general partner does not constitute “cause”.

 

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:

 

 

 

 

 

 

 

 

 

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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 of our general partner 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 IDRs, without the approval of the conflicts committee of its board of directors of our general partner 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 IDRs in the prior two quarters. Our general partner’s general partner interest in us (currently 1.7%) will be maintained at the percentage that existed immediately prior to the reset election. 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 IDRs 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 or group 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 of our general partner.

 

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

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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 Distribution Reinvestment Plan (“DRIP”) or our continuous offering program, or other equity securities of equal or senior rank, will have the following effects:

 

 

 

 

 

 

 

USA Compression Holdings and Argonaut Private Equity, L.L.C. 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 5,020,177 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. Argonaut Private Equity, L.L.C. (“Argonaut”) holds an aggregate of 6,902,332 common units. In addition, USA Compression Holdings and Argonaut may acquire additional common units in connection with our DRIP. We have agreed to provide USA Compression Holdings and Argonaut with certain registration rights for any common and subordinated units they own, as applicable. 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 16.0% of our outstanding common units. At the end of the subordination period, 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 42.0% 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 our 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 interests for the obligations of a limited partnership have not been clearly

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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:

 

 

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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 (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 certain 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 are 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 from the date of our initial public offering, which occurred on January 18, 2013. 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, then our cash available for distribution 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 a ruling from the IRS on this or any other tax matter affecting us.

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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.

 

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 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.

 

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.

 

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

 

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 and, therefore, negatively impact the value of an investment in our common units.

 

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied 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, the Obama administration’s budget proposal for fiscal year 2016 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. From time to time, members of the U.S. Congress propose and consider such substantive changes to the existing federal income tax laws that affect publicly traded partnerships. If successful, the Obama administration’s proposal or other similar proposals could eliminate 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. Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships 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 could negatively impact the value of an investment in our common units.

 

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.

 

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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.

 

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 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 the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a 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 (“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 subject to withholding taxes imposed at the highest tax rate applicable to such non-U.S. persons, and each non-U.S. person will be required to file U.S. federal income tax returns and pay tax on its 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. 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

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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.

 

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 have adopted certain valuation methodologies in determining unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methods or the resulting allocations, and such a challenge could adversely affect the value of our common units.

 

In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our respective assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our respective assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

 

A successful IRS challenge to these methods or allocations could adversely affect the amount, character and timing of taxable income or loss being allocated to our unitholders. It also could affect the amount of 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 calendar 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 calendar year, 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 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.

 

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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 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 several states. Many of which 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

 

We do not currently own or lease any material facilities or properties for storage or maintenance of our compression units. As of December 31, 2014, our headquarters consisted of 18,167 square feet of leased space located at 100 Congress Avenue, Austin, Texas 78701.

 

ITEM 3.Legal Proceedings

 

Please refer to Note  13 of our consolidated financial statements included in this report for a description of our Legal Proceedings.  

 

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 February 17, 2015, we had outstanding 32,036,276 common units, 14,048,588 subordinated units, a 1.7% general partner interest (“General Partner Interest”) and IDRs. As of February 17, 2015, USA Compression Holdings, LLC owned approximately 17.3% of our outstanding common units and 100% of our subordinated units. Our general partner currently owns a 1.7% 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.”

 

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The following table sets forth high and low sales prices per common unit and cash distributions per common unit to common unitholders for the periods indicated. The last reported sales price for our common units on February 17, 2015, was $19.15.

 

 

 

 

 

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Holders

 

At the close of business on February 17, 2015, based on information received from the transfer agent of the common units, we had 44 holders of record of our common units. The number of record holders does not include holders of common units 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 available cash, minimum quarterly distributions, and the General Partner Interest and the IDRs.

 

Available Cash

 

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash 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 plus cash on hand resulting from working capital borrowings made after the end of the 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 funds for distributions to our unitholders for any one or more of the next four quarters. 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

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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. On January 22, 2015, the Partnership announced a cash distribution of $0.51 per unit on its common and subordinated units. This fourth quarter distribution corresponds to an annualized distribution rate of $2.04 per unit. The distribution was paid on February 13, 2015 to unitholders of record as of the close of business on February 3, 2015. USA Compression Holdings, and Argonaut and certain other related unitholders elected to reinvest all of this distribution with respect to their units pursuant to the DRIP. Following the issuance of common units under the DRIP, USAC Compression Holdings owned 42.5% of the Partnership’s outstanding limited partner interests, and Argonaut and the related parties participating in the DRIP, owned 16.5% of the Partnership’s outstanding limited partner interests.

 

General Partner Interest and IDRs

 

Our partnership agreement provides that our general partner is entitled to its General Partner Interest 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 General Partner Interest if we issue additional units. Our general partner’s General Partner 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 IDRs) and our general partner does not contribute a proportionate amount of capital to us in order to maintain its  General Partner Interest. Our partnership agreement does not require that our 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.

 

IDRs 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 IDRs, but may transfer these rights separately from its General Partner Interest and without the consent of our limited partners.

 

Issuer Purchases of Equity Securities

 

None.

 

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

 

None.

 

Equity Compensation Plan

 

For disclosures regarding securities authorized for issuance under equity compensation plans, see Part III, Item 12 (“Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters”).

 

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, 2014, 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 Part II, Item 7.

 

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 consolidated financial statements are presented in two distinct periods to indicate the application of two different bases of accounting between the periods

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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.”

 

The following table includes the non-GAAP financial measure of gross operating margin, Adjusted EBITDA and Adjusted distributable cash flow (or “Adjusted DCF”). For definitions of Gross Operating Margin, Adjusted EBITDA and Adjusted DCF, and reconciliations to such measures to their most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Non-GAAP Financial Measures” below.

 

 

 

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Non-GAAP Financial Measures

 

Gross Operating Margin

 

Gross operating margin is a non-GAAP financial measure. We define 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 is impacted primarily by the pricing trends for service operations and cost of operations, including labor rates for service technicians, volume and per unit costs for lubricant oils, quantity and pricing of routine preventative maintenance on compression units and property tax rates on compression units.  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.

 

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

 

 

 

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Adjusted EBITDA

 

We define EBITDA as net income before net interest expense, depreciation and amortization expense, and income taxes. We define Adjusted EBITDA as EBITDA plus impairment of compression equipment, interest income, unit based compensation expense, restructuring charges, management fees, expenses under our operating lease with Caterpillar, certain fees and expenses related to the Holdings Acquisition, (gain) loss on sale of assets, and transaction expenses. 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, 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:

 

 

 

 

 

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.

 

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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.

 

Because we use capital assets, depreciation, impairment and the interest cost of acquiring compression equipment are also necessary elements of our costs. Expense related to unit-based compensation expense related to equity awards to employees is also a necessary component of 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 (in thousands):

 

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Adjusted Distributable Cash Flow

 

We define distributable cash flow as net income plus non-cash interest expense, depreciation and amortization expense, unit based compensation expense and impairment of compression equipment, less maintenance capital expenditures. We define Adjusted DCF as distributable cash flow plus certain transaction fees and (gain) loss on sale of equipment. We believe distributable cash flow and Adjusted DCF are important measures of operating performance because they allow management, investors and others to compare basic cash flows we generate (prior to the establishment of any retained cash reserves by our general partner and the effect of the DRIP) to the cash distributions we expect to pay our unitholders. Using distributable cash flow and Adjusted DCF, management can quickly compute the coverage ratio of estimated cash flows to planned cash distributions.

 

Distributable cash flow and Adjusted DCF 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 distributable cash flow and Adjusted DCF as presented may not be comparable to similarly titled measures of other companies.

 

Because we use capital assets, depreciation and impairment of compression equipment, (gain) loss on sale of assets, and maintenance capital expenditures are necessary elements of our costs. Expense related to unit-based compensation expense related to equity awards to employees is also a necessary component of 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 DCF, to evaluate our financial performance and our liquidity. Our Adjusted DCF 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 DCF 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.

 

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

 

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The following table summarizes certain coverage ratios for the periods presented.

 

 

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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”).

 

Overview

 

We provide compression services in a number of shale plays throughout the U.S., including the Utica, Marcellus, Permian Basin, Eagle Ford, Mississippi Lime, Granite Wash, Woodford, Barnett, Haynesville and Fayetteville shales. The demand for our services is driven by the domestic production of natural gas and crude oil; as such, we have focused our activities in areas of attractive production growth, which are generally found in these shale and unconventional resource plays.  According to recent studies promulgated by the Energy Information Agency (“EIA”), the production and transportation volumes in these plays is expected to increase over time due to the comparably attractive economic returns versus returns achieved in many conventional basins. Furthermore, the changes in production volumes and pressures of shale plays over time require a wider range of compression services than in conventional basins. We believe the flexibility of our compression units positions us well to meet these changing operating conditions. While our business focuses largely on compression services serving infrastructure installations, including centralized natural gas gathering systems and processing facilities, utilizing large horsepower compression units, typically in shale plays, we also provide compression services in more mature conventional basins, including crude oil wells targeted by horizontal drilling techniques. The recent advent of horizontal drilling has allowed producers to produce incremental volumes of crude oil on economic terms that tend to remain attractive even in periods of low commodity prices. 

 

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General Trends and Outlook

 

A significant amount of our assets are utilized in infrastructure applications, primarily in centralized natural gas gathering systems and processing facilities. Given the project nature of these applications and long-term investment horizon of our customers, we have generally experienced stability in rates since 2011 and expect to see continued stability over the medium-to-long term.  A small portion of our fleet is used in connection with crude oil production using horizontal drilling techniques.  The recent advent of horizontal drilling has allowed producers to produce incremental volumes of crude oil on economic terms that tend to remain attractive even in periods of low commodity prices.  In recent months, commodity prices have declined significantly.  As a result, we have experienced and expect to continue to experience some pressure on service rates until such time as commodity prices return to higher levels. We are closely monitoring developments in our customer base, but believe that there will continue to be demand for our services given the necessity of compression services in allowing for the transportation and processing of natural gas as well as the production of crude oil. We intend to prudently grow the number of compression units in our fleet in order to be positioned to take advantage of attractive market opportunities, primarily through the purchase of larger horsepower units that tend to generate higher margins and command longer contract terms.

 

Our ability to increase our revenues is dependent in large part on our ability to add new revenue generating compression units to our fleet while maintaining our utilization and contract rates. For the year ended December 31, 2014, we ordered approximately 350,000 horsepower of new compression unit equipment, up from the 220,000 horsepower that we expected at year end December 31, 2013 to be delivered during 2014.  Revenue generating horsepower increased by 26.2% from December 31, 2013 to December 31, 2014.  We continue to have utilization rates in excess of 90%. Average revenue generating horsepower increased by 33.1% from the year ended December 31, 2013 to the year ended December 31, 2014.

 

The EIA has projected that continued natural gas production growth will be supported in the coming years by increases in drilling efficiencies as well as a backlog of drilled but uncompleted wells in major supply areas, such as the Marcellus Shale. Additionally, domestic exports, both to Mexico and through the start-up of various liquefied natural gas (“LNG”) projects in late 2015 and beyond, are expected to increase. The EIA projects that over 70% of the increased natural gas production to meet such LNG export demand will come from shale resources.  Due to the more pronounced volatility in the price of crude oil, we expect to experience a general slowdown in the demand for our compression services for gas lift applications, and as a result some customers have sought service rate relief until commodity prices recover. However, we remain confident that through prudent management of our fleet we will be able to maintain strong utilization throughout 2015.

 

During periods of lower crude oil and natural gas prices, crude oil and natural gas production growth could moderate or decline in the U.S. A 1% decrease in average revenue generating horsepower of our active fleet during the year ended December 31, 2014 would have resulted in a decrease of approximately $2.2 million and $1.5 million in our revenue and gross operating margin, respectively. Gross operating margin is a non-GAAP financial measure. For a reconciliation of gross operating margin to net income, its most directly comparable financial measure, calculated and presented in accordance with GAAP, please read Part II, Item 6 (“Non-GAAP Financial Measures”).  Please also read Part I, Item 1A (“Risk Factors — Risks Related to Our Business) — A long-term reduction in the demand for, or production of, natural gas or crude oil in the locations where we operate could adversely affect the demand for our services or the prices we charge for our services, which could result in a decrease in our revenues and cash available for distribution unitholders”).

 

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 crude oil, and operate in a number of U.S. natural gas shale plays, including the Fayetteville, Marcellus, Woodford, Barnett, Eagle Ford, Utica, Permian Basin and Haynesville shales. Our customers use our services primarily in large volume gathering systems, processing facilities and transportation applications as well as in gas-lift compression for crude oil wells. 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

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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 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. 

 

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 cash available for distribution. The recent volatility in commodity prices has caused many of our customers to reconsider near-term capital budgets, which impacts large-scale natural gas infrastructure and crude oil production activities. We expect the drop in natural gas prices will cause a  delay or cancellation of some customers’ projects, and as a result, we have reflected that possibility in our 2015 capital budget.

 

Supply and Demand for Natural Gas and Crude Oil

 

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. As mentioned above in “General Trends and Outlook,” the EIA continues to forecast robust total growth in both overall U.S. natural gas production as well as production from shale formations. We believe this long-term increasing demand for natural gas will create increasing demand for compression services, for both existing 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 declines in natural gas prices have a 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.

 

The continued development of horizontal drilling, particularly in crude oil wells, has allowed producers to produce incremental volumes of crude oil from tight oil formations on attractive economic terms. The EIA continues to forecast growth in both overall domestic crude oil production and production from tight oil formations. Gas lift and other artificial lift technologies are critical to the enhancement of production of oil from horizontal wells operating in tight shale plays. Gas lift is a process by which natural gas is injected into the production tubing, thus reducing the hydrostatic pressure and allowing the oil to flow at a higher rate. We believe that our flexible fleet of smaller horsepower units that are primarily utilized in gas lift applications will enable us to capitalize on this growing market demand. While the recent volatility in global crude oil prices may lead to a decline in overall drilling activity, the EIA continues to project near-term crude oil production growth, albeit at a slower rate. This growth in production is expected to be supported by producers redirecting capital investment away from marginal acreage and towards core areas of major tight oil plays.

 

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

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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.

 

Operating Highlights

 

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

 

 

 

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The 28.8% increase in fleet horsepower as of December 31, 2014 is attributable to the compression units added to our fleet to meet the incremental demand by new and current customers, as a result of increasing natural gas and, to a lesser extent, crude oil production.  The 26.2% increase in revenue generating horsepower was primarily due to organic growth in our core midstream fleet. The 29.9% decrease in average horsepower per revenue generating compression unit was primarily due to the addition of a fleet of smaller horsepower units in connection with the S&R Acquisition in the fourth quarter of 2013, which had the effect of decreasing the average horsepower per revenue generating compression unit over the twelve month period ended December 31, 2014. 

 

The 30.8% increase in fleet horsepower as of December 31, 2013 was attributable to the compression units added to our fleet to meet the incremental demand by new and current customers and the S&R Acquisition. The 34.8% increase in revenue generating horsepower was primarily due to organic growth in our core midstream fleet and acquiring compression units under contract in connection with the S&R Acquisition. The average horsepower per revenue generating compression unit decreased from 791 to 720, or 9.0%, over that same period, due to the smaller horsepower gas lift units that were added to the fleet in the S&R Acquisition.

 

 

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Adjusted EBITDA.   The increase in Adjusted EBITDA during the year ended December 31, 2014 was primarily attributable to higher gross operating margin as a result of a 26.2% increase in horsepower during 2014 and a full year impact of the horsepower added in 2013 both organically and through the S&R Acquisition, partially offset by higher selling, general and administrative expense.

 

The increase in Adjusted EBITDA during the year ended December 31, 2013 was primarily attributable to higher gross operating margin as a result of a 34.8% increase in horsepower during 2013 in connection with the S&R

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Acquisition, as well as organic growth. The S&R Acquisition accounted for $9.5 million of Adjusted EBITDA from the date of acquisition (August 30, 2013) through December 31, 2013. 

 

Adjusted Distributable Cash Flow.  The increase in Adjusted DCF during the year ended December 31, 2014 was primarily due to increases in the gross operating margin as a result of a 26.2% increase in horsepower during 2014 and a full year impact of the horsepower added in 2013 both organically and through the S&R Acquisition, partially offset by higher selling, general and administrative expense, higher maintenance capital expenditures, and higher cash interest expense, net.  

 

The increase in Adjusted DCF during the year ended December 31, 2013 was primarily attributable to higher gross operating margin as a result of a 34.8% increase in horsepower during 2013 in connection with the S&R Acquisition, as well as organic growth, and lower cash interest expense, partially offset by higher maintenance capital expenditures.  The S&R Acquisition accounted for $9.2 million of Adjusted DCF from the date of acquisition (August 30, 2013) through December 31, 2013. 

 

Financial Results of Operations

 

Year ended December 31, 2014 compared to the year ended December 31, 2013

 

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

 

 

 

Contract operations revenue.  During 2014, we saw an increase in overall natural gas activity in the U.S. and experienced an increase in demand for our compression services.  Because the demand for our services is driven primarily by production of natural gas, we focus our activities in areas of attractive growth, which are generally found in certain shale and unconventional resource plays, as discussed above under the heading “Factors That Affect Our Future Results.”  The 33.1% increase in average revenue generating horsepower was primarily due to organic growth along with the full year impact of the addition of assets in connection with the S&R Acquisition in August 2013. Average revenue per revenue generating horsepower per month increased by 10.0%, primarily due to higher revenue per horsepower per month from the full year impact of the addition of smaller horsepower compression units in connection with the S&R

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Acquisition and organic growth thereafter. Smaller horsepower compression units typically generate higher revenue per horsepower per month than large horsepower compression units. The 24.1% increase in revenue generating compression units and the 26.2% increase in revenue generating horsepower as of December 31, 2014 was primarily due to organic growth.

 

Parts and service revenue.  Parts and service revenue was comprised of pass-through revenue and retail service revenue.  Pass-through revenue was earned primarily on freight and crane charges that are directly reimbursable by our customers, for which we earn no margin.  Retail service revenue consisted of maintenance work on units at our customers’ locations that are outside the scope of our core maintenance activities.  We offered these services as a courtesy to our customers and the demand fluctuates from period to period based on the varying needs of our customers.

 

Cost of operations, exclusive of depreciation and amortization. The increase in cost of operations was primarily attributable to the increase in our fleet size. Certain cost increases consisted of (1) a $9.2 million increase in direct labor expenses, (2) a $4.5 million increase in lubrication oil expenses due to an 88.3% increase in gallons consumed, partially offset by a 2.9% decrease in the average price per gallon paid, (3) a $3.1 million increase in property taxes, (4) a $2.7 million increase in maintenance parts, (5) a $2.0 million increase in retail parts and services, (6) a $1.7 million increase related to the vehicle fleet, and (7) a $0.9 million increase in training and safety expense. The 88.3% increase in gallons of lubrication oil consumed was a result of an increase in the number of smaller horsepower gas lift units within our fleet for which we are responsible for providing fluids.  The cost of fluids was generally included in service fees quoted to customers. These factors were primarily attributable to the increase in our fleet size due to organic growth, along with a full year of operations related to assets acquired in connection with the S&R Acquisition. 

 

Gross operating margin. The $42.7 million increase in gross operating margin was due to higher revenues offset by higher operating expenses during the year. The 1.9% decrease in gross operating margin percentage from 68.5% for the year ended December 31, 2013 to 66.5% for the year ended December 31, 2014 was partially attributable to (1) an increase in property taxes for the units acquired in the S&R Acquisition, (2) higher parts costs associated with the larger horsepower units placed in late 2013 and throughout 2014, and (3) an increase in remote monitoring expenses as we continue to add the monitoring service to more compression units in our fleet.

 

Selling, general and administrative expense. Approximately $6.0 million of the increase in selling, general and administrative expense was related to a rise in salaries and benefits related to (i) an increase in employee headcount to support operations and sales management and (ii) the addition of certain additional executive positions. Additionally, we expensed an additional $1.7 million of unit-based compensation expense related to the issuance of phantom units in 2014 under our 2013 Long-Term Incentive Plan (the “LTIP”), along with a $0.5 million increase in professional fees. The selling, general and administrative employee headcount was 110 as of December 31, 2014, a 37.5% increase from December 31, 2013. The selling, general and administrative employee headcount increased to support the continued growth of the business, including growth resulting from the S&R Acquisition.

 

Depreciation and amortization expense. The $17.9 million increase in depreciation expense was related to an increase in gross property and equipment balances during 2014 and a full year impact of depreciation expense on assets acquired in connection with the S&R Acquisition.  The $0.4 million increase in amortization expense was primarily due to a full year of amortization expense on intangible assets acquired in connection with the S&R Acquisition.

 

Impairment of compression equipment.  During 2014 we evaluated the future deployment of our idle fleet and, as a result, recognized impairment on certain compression units and reduced the book value of each such unit to its estimated fair value.  The fair value of each such unit was estimated based on an analysis of the expected net sale proceeds compared to other recently sold compression units in our fleet, other units recently offered for sale by third parties, and the estimated component value of the compression units of a similar type remaining in our fleet.

 

Interest expense, net.  The increase in net interest expense was attributable to the impact of a $127.9 million increase in average outstanding borrowings, offset by a $0.9 million decrease in amortization of deferred loan costs, $1.3 million of interest income related to the Capital Lease Transaction (as defined in Note 5 of our consolidated financial statements) and lower interest rates.  Average borrowings outstanding under our revolving credit facility were $498.7 million for the

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year ended December 31, 2014 compared to $370.8 million for the year ended December 31, 2013.  Our revolving credit facility had an average interest rate of 2.22% and 2.43% during December 31, 2014 and 2013, respectively.

 

Income tax expense.  This line item represents the Texas franchise tax (applicable to income apportioned to Texas). We incurred $102,738 and $279,972 in franchise tax for the years ended December 31, 2014 and 2013, respectively, as a result of the Texas franchise tax.

 

Year ended December 31, 2013 compared to the year ended December 31, 2012

 

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

 

 

 

Contract operations revenue. The increase in revenue was attributable to both organic growth as well as the S&R Acquisition.  During 2013, we saw an increase in overall natural gas activity in the U.S. and experienced a corresponding increase in demand for our compression services.  Because the demand for our services is driven primarily by production of natural gas, we focus our activities in areas of attractive growth, which were generally found in certain shale and unconventional resource plays, as discussed above under the heading “Factors that Affect Our Future Results”.  The S&R Acquisition accounted for $14.5 million of revenue from the date of acquisition (August 30, 2013) through December 31, 2013.  The 20.3% increase in average revenue generating horsepower was primarily due to 13.8% organic growth and 6.5% due to the addition of assets in connection with the S&R Acquisition. Average revenue per revenue generating horsepower per month increased by 5.7%, of which 4.7% was due to higher revenue per horsepower per month from the addition of assets in connection with the S&R Acquisition. Revenue generating compression units increased by 118.5%, of which 109.8% was due to the addition of assets in connection with the S&R Acquisition and 8.7% was due to organic growth. Revenue generating horsepower increased by 34.8%, of which 15.7% was due to organic growth and 19.1% was due to the addition of assets in connection with the S&R Acquisition.

 

Parts and service revenue. Parts and service revenue was $2.6 million for the year ended December 31, 2013 compared to $2.4 million in 2012, or a 6.0% increase.

 

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Cost of operations, exclusive of depreciation and amortization. The increase was primarily attributable to the increase in our fleet size as a result of the organic growth described above and the S&R Acquisition. The following costs increased as a result of the growth in our fleet size (1) a $1.5 million increase in lubrication oil expenses due to a 21.7% increase in gallons consumed, partially offset by a 3.9% decrease in the average price per gallon paid, (2) a $2.4 million increase in direct labor expenses, (3) a $0.9 million increase in training and safety expense, (4) a $0.2 million increase related to vehicle tools and gasoline and (5) a $4.4 million increase in cost of operations due to the S&R Acquisition. In addition, business and property insurance increased by $0.4 million primarily due to certain insurance claims on our compression units and the increase in the size of our fleet. The cost of operations was 31.5% of revenue for the year ended December 31, 2013 as compared to 31.8% for the year ended December 31, 2012.

 

Gross operating margin. The $23.8 million increase in gross operating margin was due to higher revenues offset by operating expenses during the year. The gross operating margin percentage was materially consistent with 2012.

 

Selling, general and administrative expense. Approximately $3.1 million of the increase in selling, general and administrative expense was related to a rise in salaries and benefits due to (i) an increase in employee headcount to support operations and sales management and (ii) the addition of certain executive positions to operate as a public company. Additionally, the Partnership expensed $1.3 million of unit-based compensation expense related to the issuance of phantom units in 2013 under the LTIP. Other significant increases included (1) a $0.5 million due to increased sales support costs, (2) $3.8 million of increased professional fees, including $2.1 million related to the S&R Acquisition and (3) $0.3 million of increased computer hardware and software expenses, all of which were attributable to increased employee headcount and support services and (4) $0.6 million increase in expenses due to the S&R Acquisition, primarily related to personnel costs.  In addition, business and property insurance increased by $0.6 million due to certain insurance claims on our compression units and the increase in the size of our fleet and were offset by a $1.0 million decrease in management fees that are no longer owed by the Partnership subsequent to its initial public offering. The selling, general and administrative employee headcount was 86 (including 6 as a result of the S&R Acquisition) at December 31, 2013, a 45.8% increase from December 31, 2012. The selling, general and administrative employee headcount increased to support the continued growth of the business, including the S&R Acquisition. Selling, general and administrative expense represented 18.0% and 15.4% of revenue for the years ended December 31, 2013 and 2012, respectively.

 

Depreciation and amortization expense. The 26.4% increase in depreciation and amortization expense was related to an increase in property, plant and equipment, including the S&R Acquisition, of 39.8% for the year ended December 31, 2013 as compared to December 31, 2012.  For the period of August 30, 2013 to December 31, 2013 the S&R Acquisition accounted for $3.7 million of depreciation and amortization.

 

Interest expense. Included in interest expense was amortization of deferred loan costs of $2.2 million and $1.9 million for the years ended December 31, 2013 and 2012, respectively. Interest expense for both periods was related to borrowings under our revolving credit facility. Average borrowings outstanding under our revolving credit facility were $370.8 million for the year ended December 31, 2013 compared to $442.1 million for the year ended December 31, 2012. Our revolving credit facility had an interest rate of 2.17% and 2.96% at December 31, 2013 and 2012, respectively, and an average interest rate of 2.43% and 2.99%, excluding the effects from the interest rate swap instruments discussed below for 2012. The composite fixed interest rate for $140 million of notional coverage under three interest rate swap instruments was 2.52% at December 31, 2011 plus the applicable margin of 2.75%. These interest rate swaps expired during 2012. We did not designate our swap agreements as cash flow hedges. As a result, amounts paid or received from the interest rate swaps were charged or credited to interest expense. For the year ended December 31, 2012, we recorded a fair value gain of $2.2 million, with respect to these swaps as a reduction in interest expense.

 

Income tax expense. We incurred approximately $279,972 and $196,040 in franchise tax for the years ended December 31, 2013 and 2012, respectively, as a result of the Texas franchise tax.

 

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Liquidity and Capital Resources

 

Overview

 

We operate in a capital-intensive industry, and our primary liquidity needs are to finance the purchase of additional compression units and other capital expenditures, service our debt, fund working capital, and pay distributions. As described below, our revolving credit facility contains a financial covenant requiring us to maintain leverage below a maximum leverage ratio.  As a result of our need to comply with such financial covenant, we expect borrowings under our revolving credit facility, cash generated from operations and issuance of debt securities will likely be insufficient to fund all of our short-term liquidity needs and that we will likely need to issue equity securities in the next twelve months.  We expect, however, to be able to remain in compliance with such financial covenant by one or more of the following actions: delay a discretionary portion of our capital expenditures; issue equity in conjunction with the acquisition of another business; issue equity in a public or private offering; or request an equity infusion pursuant to the terms of our revolving credit facility.

 

In addition to organic growth, we may also consider a variety of assets or businesses for potential acquisition. Because we distribute all of our available cash, we expect to fund any future capital expenditures or acquisitions primarily with capital from external financing sources, such as borrowings under our revolving credit facility and issuances of debt and equity securities.  In addition, as our fleet matures and expands, our long-term maintenance capital expenditures will likely increase. We are not aware of any regulatory changes or environmental liabilities that we currently expect to have a material impact on our current or future operations. Please see “—Capital Expenditures” below.

 

Cash Flows

 

The following table summarizes our sources and uses of cash for the years ended December 31, 2014, 2013 and 2012:

 

 

 

Net cash provided by operating activities.  The increase in net cash provided by operating activities from the year ended December 31, 2013 to the year ended December 31, 2014 relates primarily to higher gross operating margin offset by higher selling, general and administrative expenses. 

 

Net cash provided by operating activities increased for the year ended December 31, 2013 from the year ended December 31, 2012. The increase relates primarily to an increase in net income during the year ended December 31, 2013, due to the increase in the size of our operating fleet, and a $4.5 million increase in working capital in 2013 due to increased purchases and timing of payments for new compression units and related equipment.

 

Net cash used in investing activities. For the year ended December 31, 2014, net cash used in investing activities related primarily to the purchase of new compression units in response to increased demand, partially offset by $1.4 million of proceeds from the sale of equipment during 2014. 

 

For the year ended December 31, 2013, net cash used in investing activities related primarily to the purchase of new compression units, partially offset by (1) $2.2 million of proceeds from the sale of equipment during the 2013 and (2) cash received as part of a purchase price adjustment related to the S&R Acquisition of $3.4 million during 2013.

 

Net cash provided by financing activities.  During 2014, we borrowed, on a net basis, $173.9 million primarily to support our purchases of new compression units and related equipment, as described above. During May 2014, we

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completed an equity offering and utilized the net proceeds of $138.0 million to pay down our revolving credit facility. During 2014, we also made distributions to our unitholders of $32.3 million.

 

For the year ended December 31, 2013, we paid down, on a net basis, $81 million on our revolving credit facility due primarily to the application of $180.6 million in proceeds from our initial public offering, offset by approximately $100 million in net borrowings to support our purchases of new compression units and related equipment. During 2013, we also made distributions to our unitholders of $14.7 million.

 

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:

 

 

 

We classify capital expenditures as maintenance or expansion on an individual asset basis. We expect that our maintenance capital expenditure requirements will continue to increase as the overall size and age of our fleet increases. Our aggregate maintenance capital expenditures for the years ended December 31, 2014 and 2013 were $15.8 million and $14.3 million, respectively.  We currently plan to spend approximately $20 million in maintenance capital expenditures during 2015.

 

Given our growth objectives and anticipated demand from our customers as a result of the increasing natural gas activity described above under the heading “—General Trends and Outlook,” we anticipate that we will continue to make significant expansion capital expenditures.  Without giving effect to any equipment we may acquire pursuant to any future acquisitions, we currently expect to spend between  $250 million and $270 million in expansion capital expenditures during 2015. Our expansion capital expenditures for the years ended December 31, 2014 and 2013 were $372.1 million and $323.7 million, respectively. Of the $323.7 million in 2013, $178.5 million (including $120.0 million of fixed assets, $7.6 million of intangible assets and $51.0 million of goodwill) related to the S&R Acquisition and was financed through the issuance of 7,425,261 common units to S&R’s owners.

 

Description of Revolving Credit Facility

 

As of December 31, 2014, we had outstanding borrowings of $594.9 million, borrowing availability based on our borrowing base of $255.1 million and, subject to financial covenants as of December 31, 2014, borrowing availability under our revolving credit facility of $133.3 million. The borrowing base consists of eligible accounts receivable, inventory and compression units. Financial covenants permitted a maximum leverage ratio of 5.50 to 1.0 as of December 31, 2014 and 5.95 to 1.0 as of March 31, 2015.  As of February 17, 2015, we had outstanding borrowings of $657.4 million.

 

For a detailed description of our revolving credit facility including the covenants and restrictions contained therein, please see Note 7 to our consolidated financial statements.

 

Sale of Common Units

 

In May 2014, we sold 5,600,000 common units at a price to the public of $25.59 per common units, resulting in proceeds, net of underwriting discounts and offering expenses of $138.0 million. We primarily used the proceeds from this offering to reduce borrowings under our revolving credit facility. In connection with this offering, certain selling

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unitholders, including USA Compression Holdings and Argonaut, sold a combined total of 1,990,000 common units. We did not receive any proceeds from the common units sold by such selling unitholders.

 

Distribution Reinvestment Plan

 

The DRIP provides our common unitholders a means by which they can increase the number of common units they own by reinvesting the quarterly cash distributions, which they would otherwise receive in cash, into the purchase of additional common units.  As of February 17, 2015, a total of 3,882,146 common units had been issued pursuant to the DRIP.

 

Continuous Offering Program

 

On November 12, 2014, we entered into an Equity Distribution Agreement with the sales agents party thereto, which established our continuous offering program whereby we may issue common units having an aggregate offering amount of up to $150 million (the “COP”). We did not issue any common units or receive any proceeds under the COP in the year ended December 31, 2014.

 

Total Contractual Cash Obligations

 

The following table summarizes our total contractual cash obligations as of December 31, 2014:

 

 

 

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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

 

Please refer to Note 13 of our consolidated financial statements included in this report for a description of our commitments and contingencies, including off-balance sheet arrangements.  

 

Critical Accounting Policies and Estimates

 

The discussion and analysis of our financial condition and results of operations is based upon our financial statements. These financial statements were prepared in conformity with GAAP. As such, we are required to make certain estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the

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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:

 

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. Goodwill is not amortized, but is reviewed for impairment annually based on the carrying values as of October 1, or more frequently if impairment indicators arise that suggest the carrying value of goodwill may not be recovered.

 

Goodwill—Impairment Assessments

 

We test for potential impairment of goodwill annually on October 1 of the fiscal year and additionally whenever indicators of impairment arise. The timing of the annual test may result in charges to our statement of operations in our fourth fiscal quarter that could not have been reasonably foreseen in prior periods.

 

As described in Note 1 to our consolidated financial statements in order to estimate the fair value of goodwill we use a weighted combination of a discounted cash flow model, distributable cash flow, and a multiple of EBITDA (known as the income approach) and calculation of our market capitalization (known as the market capitalization approach). The income approach requires us to use a number of assumptions, including market factors specific to the business, the amount and timing of estimated future cash flows to be generated by the business over an extended period of time, long-term growth rates for the business, and a rate of return that considers the relative risk of achieving the cash flows and the time value of money. We have one reporting unit and evaluate cash flows at the reporting unit level.  Although the assumptions we use in our discounted cash flow model are consistent with the assumptions we use to generate our internal strategic plans and forecasts, significant judgment is required to estimate the amount and timing of future cash flows and the relative risk of achieving those cash flows. When using the market capitalization approach, we make judgments about the comparability of publicly traded partnerships engaged in similar businesses. We base our judgments on factors such as size, growth rates, profitability, risk, control premium, and return on investment. We had a total of $208.1 million in goodwill on our balance sheet as of December 31, 2014, all of which is allocated to our single reporting unit. 

 

On October 1, 2014, we performed our annual goodwill impairment test. We updated our impairment test as of December 31, 2014 as certain potential impairment indicators were identified during the fourth quarter. As described in Note 1, “Description of Business and Summary of Significant Accounting Policies – Goodwill,” in step one of that test we compared the estimated fair value of each reporting unit to its carrying value. The estimated fair value of our reporting unit of $1.5 billion as of December 31, 2014 exceeded its carrying value of $1.4 billion by approximately 7%, or $100 million, and we concluded that it was not impaired. Consequently, we recorded no goodwill impairment charges for the twelve months ended December 31, 2014.

 

As discussed above, estimates of fair value can be affected by a variety of external and internal factors. The recent crude oil price volatility has caused disruptions in global energy industries and markets. Potential events or circumstances that could reasonably be expected to negatively affect the key assumptions we used in estimating the fair value of our reporting unit include the consolidation or failure of crude oil and natural gas producers, which may result in a smaller market for services and may cause us to lose key customers, and cost-cutting efforts by crude oil and natural gas producers, which may cause us to lose current or potential customers or achieve less revenue per customer. If the estimated fair value of our reporting unit declines due to any of these factors, we may be required to record future goodwill impairment charges.

 

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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, including the removal of compression units from our active fleet, 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, the expected net sale proceeds compared to other fleet units we recently sold, a review of other units recently offered for sale by third parties, or the estimated component value of similar equipment we plan to continue to use.  We recorded $2.3 million and $0.2 million in impairment of compression equipment for the years ended December 31, 2014 and 2013, respectively. We did not record impairment of long-lived assets in 2012.

 

Potential events or circumstances that could reasonably be expected to negatively affect the key assumptions we used in estimating whether or not the carrying value of our long-lived assets are recoverable  include the consolidation or failure of crude oil and natural gas producers, which may result in a smaller market for services and may cause us to lose key customers, and cost-cutting efforts by crude oil and natural gas producers, which may cause us to lose current or potential customers or achieve less revenue per customer. If our projections of cash flows associated with our units decline, we may have to record an impairment of compression equipment in future periods.

 

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 of customer bad debt and make adjustments to the allowance as necessary. The allowance for doubtful accounts was $374,198, $246,410 and $259,638 as of December 31, 2014, 2013 and 2012, 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.

 

Revenue from compression services is recognized as earned under our fixed fee contracts. Compression services generally are billed monthly in advance of the service period, except for certain customers which are billed at the beginning of the service month, and are recognized as deferred revenue on the balance sheet until earned.

 

Recent Accounting Pronouncements

 

We qualify as an emerging growth company under Section 109 of the Jumpstart Our Business Startups, (“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.

 

For more discussion on specific recent accounting pronouncements affecting us, please see Note 12 to our consolidated financial statements.

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ITEM 7A.Quantitative and Qualitative Disclosures About Market Risk

 

Commodity Price Risk

 

Market risk is the risk of loss arising from adverse changes in market rates and prices. We do not take title to any natural gas or crude oil in connection with our services and, accordingly, have no direct revenue exposure to fluctuating commodity prices. However, the demand for our compression services depends upon the continued demand for, and production of, natural gas and crude oil. 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.

 

Historically, crude oil and natural gas prices in the U.S. have been volatile. Global crude oil prices have fallen recently compared to levels seen over the past 18 months. West Texas Intermediate crude oil spot prices as of December 31, 2014 were 50% and 46% lower than prices at June 30, 2014 and December 31, 2013, respectively. Periods of lower crude oil and natural gas prices could potentially have a negative impact on the demand for our compression services. A 1% decrease in average revenue generating horsepower of our active fleet during the year ended December 31, 2014 would have resulted in a decrease of approximately $2.2 million and $1.5 million in our revenue and gross operating margin, respectively. Gross operating margin is a non-GAAP financial measure. For a reconciliation of gross operating margin to net income, its most directly comparable financial measure, calculated and presented in accordance with GAAP, please read Part II, Item 6 (“— Non-GAAP Financial Measures”).

 

Interest Rate Risk

 

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

 

As of December 31, 2014 we had approximately $594.9 million of variable-rate outstanding indebtedness at a weighted-average interest rate of 2.22%. A 1% increase in the effective interest rate on our variable-rate outstanding debt as of December 31, 2014 would result in an annual increase in our interest expense of approximately $5.9 million.

 

For further information regarding our exposure to interest rate fluctuations on our debt obligations, see Note 7 to our consolidated financial statements. We may, in the future, hedge all or a portion of our variable rate debt.

 

Credit Risk

 

Our credit exposure generally relates to receivables for services provided. If any significant customer of ours should have credit or financial problems resulting in a delay or failure to repay the service fees owed 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.

 

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

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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 to allow timely decisions regarding required disclosures, and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.  Based upon the evaluation, our principal executive officer and principal financial officer have concluded that, except with respect to the event described below, our disclosure controls and procedures were effective as of December 31, 2014 at the reasonable assurance level.

 

In connection with another filing, we identified that the Partnership had not timely filed a Current Report on Form 8-K relating to the appointment by the board of directors of our general partner of Michael D. Lenox as principal accounting officer of the Partnership, The Partnership filed the Current Report on Form 8-K promptly after such identification, and our management has designed additional controls and procedures to provide reasonable assurance that we timely file future Current Reports on Form 8-K within the time periods specified in the rules and forms of the SEC relating to such reports.

 

Management’s Annual Report on Internal Control Over Financial Reporting

 

Our management is responsible for establishing and maintaining adequate internal control over financial reporting for us. Our internal control system was designed to provide reasonable assurance regarding the preparation and fair presentation of our published financial statements.

 

There are inherent limitations to the effectiveness of any control system, however well designed, including the possibility of human error and the possible circumvention or overriding of controls. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Management must make judgments with respect to the relative cost and expected benefits of any specific control measure. The design of a control system also is based in part upon assumptions and judgments made by management about the likelihood of future events, and there can be no assurance that a control will be effective under all potential future conditions. As a result, even an effective system of internal control over financial reporting can provide no more than reasonable assurance with respect to the fair presentation of financial statements and the processes under which they were prepared.

 

Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2014. In making this assessment, management used the criteria set forth by the 2013 Committee of Sponsoring Organizations of the Treadway Commission in Internal Control — Integrated Framework. Based on this assessment, our management believes that, as of December 31, 2014, our internal control over financial reporting was effective. This report does not include an attestation report of the company’s registered public accounting firm due to a transition period established by rules of the SEC for emerging growth 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.

 

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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.

 

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 NYSE. 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.

 

The non-management directors regularly meet in executive session without management directors. Mr. Long is currently our only management director. Forrest E. Wylie presides at such meetings. Interested parties can communicate directly with non-management directors by mail in care of the General Counsel and Secretary at USA Compression Partners, LP, 100 Congress Avenue, Suite 450, Austin, Texas 78701. Such communications should specify the intended recipient or recipients. Commercial solicitations or communications will not be forwarded.

 

Independent Directors. The board of directors of our general partner has determined that Robert F. End, John D. Chandler and Forrest E. Wylie are independent directors under the standards established by the NYSE and the Exchange Act. The board of directors of our general partner 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.

 

In addition, in October 2014, Mr. Chandler was appointed to serve on the board of directors and the audit committee of CONE Midstream GP, LLC (“CONE”).  During the period of Mr. Chandler’s appointment for the year ended December 31, 2014, subsidiaries of CONE made compression service payments to us of approximately $1.7 million.  The board of directors of our general partner made a determination that the CONE relationship did not preclude the independence of Mr. Chandler.

 

Audit Committee. The board of directors of our general partner 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, John D. Chandler and Forrest E. Wylie. Mr. Chandler serves as chairman of the audit committee.  The board of directors of our general partner has determined that Mr. Chandler 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, Chandler 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 of our general partner 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, the board of directors of our general partner has established a compensation committee to, among other things, oversee the compensation plans described below in Part III, Item 11 (“Executive Compensation”). The

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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 of directors of our general partner with respect to, the compensation and benefits of the board of directors and executive officers of our general partner. 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 limited liability company agreement of our general partner, our general partner may, from time to time, establish a conflicts committee to which the board of directors of our general partner will appoint independent directors and which may be asked to review specific matters that the board of directors of our general partner 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 of our general partner, 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

 

Section 16(a) of the Exchange Act requires the board of directors and executive officers of our general partner, and persons who own more than 10 percent of a registered class of our equity securities, to file with the SEC and any exchange or other system on which such securities are traded or quoted initial reports of ownership and reports of changes in ownership of our common units and other equity securities. Officers, directors and greater than 10 percent unitholders are required by the SEC’s regulations to furnish to us and any exchange or other system on which such securities are traded or quoted with copies of all Section 16(a) forms they filed with the SEC. To our knowledge, based solely on a review of the copies of such reports furnished to us, we believe that all reporting obligations of the officers and directors of our general partner and greater than 10 percent unitholders under Section 16(a) were satisfied during the year ended December 31, 2014.

 

Corporate Governance Guidelines and Code of Ethics

 

The board of directors of our general partner 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 of our general partner and its committees. The board of directors of our general partner has also adopted a Code of Business Conduct and Ethics (the “Code”) that applies to our general partner and its subsidiaries and affiliates, including us, and to all of its and their directors, employees and officers, including its principal executive officer, principal financial officer and principal accounting officer. 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 our general partner 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.

 

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Directors and Executive Officers

 

The following table shows information as of February 17, 2015 regarding the current directors and executive officers of USA Compression GP, LLC.

 

 

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 of our general partner. 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.

 

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 the board of directors of our general partner.

 

Matthew C. Liuzzi  has served as our Vice President, Chief Financial Officer and Treasurer since January 2015. Prior to such time, Mr. Liuzzi served as our Senior Vice President – Strategic Development since joining us in April 2013. Mr. Liuzzi joined us after nine years in investment banking, since 2008 at Barclays, where he was most recently a Director in the Global Natural Resources Group in Houston.  At Barclays, Mr. Liuzzi worked primarily with midstream clients on a variety of investment banking assignments, including initial public offerings, public and private debt and equity offerings, as well as strategic advisory assignments. He holds a B.A. and an M.B.A., both from the University of Virginia. 

 

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.

 

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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 compression fabrication 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.

 

William G. Manias has served as our Vice President and Chief Operating Officer since July 2013.  He served as a director of our general partner from February 2013 to July 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 managing the partnership’s financial and treasury activities. Before joining Crestwood in January 2009, Mr. Manias was the Chief Financial Officer of TEPPCO Partners, L.P. starting in January 2006. 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.

 

John D. Chandler has served as a director of USA Compression GP, LLC since October 2013.  Mr. Chandler has also served on the board of directors and the audit committee of CONE since October 2014. From 2009 to March 2014, Mr. Chandler served as Senior Vice President and Chief Financial Officer of Magellan GP, LLC, the general partner of Magellan Midstream Partners, LP. From 2003 until 2009, he served in the same capacities for the general partner of Magellan Midstream Holdings, L.P. From 1999 to 2002, Mr. Chandler was Director of Financial Planning and Analysis and Director of Strategic Development for a subsidiary of The Williams Companies, Inc. From 1992 to 1999, Mr. Chandler held various accounting and finance positions with MAPCO Inc. Mr. Chandler received his B.S. and B.A. in accounting and finance from the University of Tulsa.

 

Mr. Chandler’s experience in the energy industry, particularly through his position as the Chief Financial Officer of the general partner of Magellan Midstream Partners, LP, will provide additional industry perspective to the board of directors of our general partner. He will bring us helpful perspective regarding company growth, having been an officer at Magellan since its spin-off from the Williams Companies in 2003. In addition, his understanding of the midstream master limited partnership sector in particular and of the unique issues related to operating publicly traded limited partnerships should help him make valuable contributions to us.

 

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.

 

Mr. Derryberry brings significant knowledge and expertise to the board of directors of our general partner from his service on other boards and his years of experience in our industry including his useful insight into investments and

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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 the board of directors of our general partner.

 

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 (“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 (“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 the board of directors of our general partner 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 the board of directors of our general partner.

 

William H. Shea, Jr. has served as a director of USA Compression GP, LLC since June 2011. Mr. Shea is also the chairman of the board of directors, President and Chief Executive Officer of Niska Gas Storage Partners LLC and has served in such role since May 2014.  Previously, Mr. Shea served as the President and Chief Operating Officer of Buckeye GP LLC and its predecessor entities (“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 March 2010, and as President and Chief Executive Officer of the general partner of Penn Virginia GP Holdings, L.P. from March 2010 to October 2013 and as Chief Executive Officer of the general partner of PVR Partners, L.P. (“PVR”), from March 2010 to October 2013. 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 PVR 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 skill set, we believe Mr. Shea is a valuable member of the board of directors of our general partner.

 

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 the board of directors of our general partner. 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.

 

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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. 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 the board of directors of our general partner.

 

Forrest E. Wylie has served as a director of USA Compression GP, LLC since March 2013. Mr. Wylie served as the Non-Executive Chairman of the board of directors of Buckeye GP LLC, the general partner of Buckeye Partners, L.P., from February 2012 to August 2014. He served as Chairman of the Board, CEO and a director of Buckeye GP LLC from June 2007 to February 2012. Mr. Wylie also served as a director of the general partner of Buckeye GP Holdings L.P., the former parent company of Buckeye (“BGH”) from June 2007 until the merger of BGH with Buckeye Partners, L.P. on November 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 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 the board of directors of our general partner.

 

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. All of our employees, including our executive officers are employees of USAC Management, a wholly owned subsidiary of our general partner. We sometimes refer herein to USAC Management’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.”

 

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, 2014, our named executive officers (“NEOs”), were:

 

 

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On January 10, 2015, Joseph C. Tusa, Jr. resigned as Vice President, Chief Financial Officer and Treasurer for personal reasons.  On January 10, 2015, the board of directors of our general partner appointed Matthew C. Liuzzi as Vice President, Chief Financial Officer and Treasurer. We expect Mr. Liuzzi to be a named executive officer for the year ending December 31, 2015.

 

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, 2013 and 2014.

 

 

 

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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.

 

 

Base Compensation For 2014 and 2015

 

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 directors of our general partner or the chief executive officer (for non-chief executive officer compensation) in conjunction with the compensation committee. No formulaic base salary increases are provided to the NEOs. For 2014 and 2015, in connection with determining base salaries for each of our NEOs, the board of directors of our general partner, compensation committee and chief executive officer worked with a compensation consultant to determine comparable salaries for our peer group, which we identified based on a review of companies in our industry with similar characteristics.

 

Based upon the information provided by the compensation consultant with respect to a review of base salary information of companies within our peer group, the board of directors of our general partner determined during 2014 to move towards targeting base salaries more directly in-line with our peer group. For 2015, the board of directors of our general partner determined that base salary should be set at approximately the 50th percentile of the peer group.  The

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2014 and current 2015 base salaries for our NEOs, including for our Chief Executive Officer, are set forth in the following table:

 

 

 

Annual Performance-Based Compensation For 2014

 

In February 2014, the board of directors of our general partner approved the adoption of an Annual Cash Incentive Plan (the “Cash Plan”). Each of our NEOs is entitled to participate in the Cash Plan and their potential bonus is governed both by the Cash Plan and their employment agreement.  The compensation committee acts as the administrator of the Cash Plan under the supervision of the full board of directors of our general partner, and has the discretion to amend, modify or terminate the Cash Plan at any time upon approval by the board of directors of our general partner.

 

The board of directors of our general partner sets a target bonus amount (the “Target Bonus”) for each NEO prior to or during the first quarter of the calendar year.  For the year ended December 31, 2014, the Target Bonus for each NEO was $500,000 for Mr. Long, $250,000 for Mr. Tusa and $175,000 for Mr. Holloway.  In connection with his resignation, Mr. Tusa forfeited his bonus. The Target Bonus is generally subject to the satisfaction of both a partnership performance goal and an individual performance goal.  Fifty percent (50%) of the Target Bonus is subject to our achievement of our budgeted adjusted distributable cash flow level (“Adjusted DCF”) for the year, as determined by our board of directors of our general partner.  Payouts with respect to the portion of the bonus subject to Adjusted DCF (the “Adjusted DCF Bonus”) generally do not occur unless we have satisfied the threshold set for Adjusted DCF.  For 2014, the board of directors of our general partner set the threshold for Adjusted DCF at $81 million. The threshold, target and maximum requirements for the Adjusted DCF target for each year, as well as the portion of the Adjusted DCF Bonus that could become payable if performance was satisfied for the year, are set forth below:

 

 

 

 

If Adjusted DCF performance falls in between threshold and target, or between target and maximum, the amounts payable are adjusted ratably using straight line interpolation.  If Adjusted DCF is satisfied above maximum levels, the potential payment of the Adjusted DCF Bonus is capped at the maximum level of 200%.

 

The remaining fifty percent (50%) of the Target Bonus is subject to individual objectives specific to each eligible individual’s role at USAC (the “Individual Bonus”).  The individual objectives are agreed upon in advance between the NEO and his immediate supervisor (or, with respect to the chief executive officer, between the board of directors of our general partner and the chief executive officer) and such objectives address the key priorities for that NEO’s position.  They may include key operating objectives as well as personal development criteria.  The Individual Bonus is subject to a maximum payout of 100% of the targeted Individual Bonus amount, although the board of directors of our general partner has discretion to pay out smaller amounts ranging from 0% to 100%, at their sole discretion, after analyzing the individual’s personal performance for the year.  In connection with the Individual Bonus for the year ended December 31, 2014, each of the NEOs met with their immediate supervisor (or, with respect to the chief executive officer, the board of directors of our general partner) to set individual objectives that reflected the responsibilities and priorities of their position.

 

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In the aggregate, the maximum amount payable with respect to a Target Bonus under the Plan is 150%, as the Adjusted DCF Bonus is capped at 200% of target and the Individual Bonus is capped at 100% of target.  Target Bonuses, if any, are paid within one week following delivery by our independent auditor of the audit of our financial statements for the year in which the Target Bonus relates, but in no case later than March 15 of the year following the year in which the Target Bonus relates. For the year ended December 31, 2014, Adjusted DCF exceeded the target threshold by slightly in excess of 6%, which resulted in the Adjusted DCF portion of the Cash Plan (comprising one-half of the overall Bonus) being paid to each NEO (except Mr. Tusa who forfeited his bonus upon resignation) at a rate of approximately 160% for such portion of the Bonus.  With respect to the Individual Bonus portion of the overall Bonus, each NEO (except Mr. Tusa who forfeited his bonus upon resignation) was determined by his immediate supervisor (which in the case of the chief executive officer is the board of directors of our general partner) to have satisfied his individual objectives and therefore was entitled to receive 100% of the Individual Bonus.  The board of directors of our general partner exercised its discretion to make immaterial adjustments to the bonus amounts for the 2014 year, thus awards made pursuant to the Cash Plan with respect to the 2014 year were:

 

 

 

As Mr. Tusa resigned prior to the delivery of the audit of our financial statements for the year ending December 31, 2014, he forfeited his award under the Cash Plan.

 

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

 

In connection with our initial public offering, our board of directors of our general partner adopted the LTIP. The LTIP was 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 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, although in 2014, as well as in 2013, we only granted phantom unit awards pursuant to the LTIP. The outstanding LTIP awards held by our NEOs are reflected in the table below.

 

During the years ended December 31, 2013 and 2014, our board of directors of our general partner granted phantom unit awards to certain key employees, including our NEOs. Each phantom unit award vests in three equal annual installments, with the first installment vesting on the first anniversary of the date of grant. In the event of cessation of an employee’s service for any reason, all phantom units that have not vested prior to or in connection with such cessation of service shall automatically be forfeited. Each phantom unit granted to an employee, including the NEOs, is granted in tandem with a corresponding distribution equivalent right, which is paid quarterly on the distribution date from the grant date until the earlier of the vesting or the forfeiture of the related phantom units.  Each distribution equivalent right entitles the participant to receive payments in the amount equal to any distribution made by us following the grant date in

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respect of the grant date in respect of the common unit underlying the phantom unit to which such distribution equivalent right relates.

 

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 (other than Mr. Holloway, who joined us after the Holdings Acquisition) 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 or, with respect to Mr. Holloway, at the time of his employment. The grants the NEOs received had time-based vesting requirements (which, for Mr. Long and Mr. Tusa, were satisfied in full as of December 31, 2013) and are designed not only to 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.  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. Available cash will be distributed to the USA Compression Holdings members at such times as determined by its board of managers, at which time the holders of Class B Units could receive distributions if the cash distributed reaches the required distribution hurdles. Distributions to the Class B Unit holders could also occur in connection with a sale or liquidation event of USA Compression Holdings.  To date, our NEOs have not received distributions with respect to these awards.

 

Outstanding Equity Awards as of December 31, 2014

 

The following table provides information regarding the Class B Units in USA Compression Holdings held by the NEOs as of December 31, 2014. None of our NEOs held any option awards that were outstanding as of December 31, 2013 and 2014. Also reflected within the table are the outstanding phantom units that were granted to our NEOs from the LTIP during the years ended December 31, 2013 and 2014, respectively.

 

 

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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 USAC Management that 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”).

 

Severance Arrangements

 

Each NEO’s employment agreement had an initial term that has been extended on a year-to-year basis 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 for any reason, all earned, unpaid annual base salary and vacation time (and, with respect to the chief executive officer, accrued, unused sick time off) shall be paid to the NEO within thirty (30) days of the date of the NEO’s termination of employment. 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 (the “Severance Period”) (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), subject to acceleration upon the NEO’s death during the Severance Period, and (ii) continued coverage for twenty-four (24) months (or, with respect to Mr. Long, thirty (30) 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 (12) months following termination, after which time continued coverage shall be provided at the NEO’s sole expense (except with respect to Mr. Long, who 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

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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. During employment and for two years following termination, each NEO’s employment agreement prohibits him from competing with our business.

 

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.

 

 

Each of the Class B Units held by the NEOs would be forfeited for no consideration if the NEO was terminated for cause.  A termination for “Cause” under the USA Compression Holdings limited liability company agreement is defined substantially the same as the term used within the employment agreements described above.  In the event that the NEO’s employment is terminated for any reason, however, USA Compression Holdings (or its nominee) shall have the right, but not the obligation, to repurchase any vested Class B Units held by the terminated NEO for then-current fair market value or other agreed value. 

 

On January 10, 2015, Mr. Tusa announced his resignation as Vice President, Chief Financial Officer and Treasurer, which resignation became effective immediately. Consistent with a voluntary resignation under his employment agreement and his phantom unit award agreements, Mr. Tusa did not receive any severance or other post-employment compensation under his employment agreement, nor did he receive any acceleration of vesting of his equity awards. 

 

Change in Control Benefits

 

We generally have double- trigger change in control benefits for our outstanding LTIP awards.  If a change in control occurs, and our NEOs are also terminated without cause or for good reason (each term as defined in the NEO’s employment agreement) in connection with that change in control event, the current LTIP phantom units would become fully vested.  The one exception to this practice is with respect to our CEO, who would receive immediate vesting of any outstanding phantom units upon the change in control event.

 

Director Compensation

 

For the year ended December 31, 2014, our NEOs who also served as directors did not receive additional compensation for their service as directors. Only the independent members of the board of directors of our general partner receive compensation for their service as directors.

 

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The following table shows the total compensation earned by each independent director during 2014.

 

 

 

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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 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:

 

 

 

 

 

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.

 

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 February 17, 2015 held by:

 

 

 

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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.

 

 

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*Less than 1%.

 

 

R/C Holdings is the record holder of approximately 97.4% 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. (“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 is a member of the board of managers of USA Compression Holdings and a member of the board of directors of our general partner, disclaims beneficial ownership of the units owned by USA Compression Holdings.

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Securities Authorized for Issuance Under Equity Compensation Plans

 

In connection with the consummation of our IPO on January 18, 2013, the board of directors of our general partner adopted the LTIP. The following table provides certain information with respect to this plan as of December 31, 2014:

 

 

 

For more information about our LTIP, please see Note 9 to our consolidated financial statements.

 

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

 

Certain Relationships And Related Party Transactions

 

In connection with our formation and IPO, 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 USAC Management, 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

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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.

 

Relationship with PVR Partners

 

William Shea, who has served as a director of our general partner since June 2011, also served as a director and the chief executive officer of the general partner of PVR Partners, L.P. (“PVR”) starting in March 2010. On March 21, 2014, PVR merged with and into Regency Energy Partners LP, a Delaware limited partnership (“Regency”), with Regency as the surviving limited partnership (the “Merger”). As a result of the Merger, the separate limited partnership existence of PVR ceased, and Regency continued its existence as the surviving limited partnership.    For the years ended December 31, 2014 and 2013, subsidiaries of PVR made compression service payments to us of approximately $0.6 million and $3.0 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 of our general partner and the terms were determined by negotiation among the parties.

 

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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:

 

 

 

 

 

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”) 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, 2014 and 2013:

 

 

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Our audit committee has adopted an audit committee charter, which is available on our website and 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.

 

PART IV

 

ITEM 15.Exhibits and Financial Statement Schedules

 

 

 

 

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

 

 

The following documents are filed as exhibits to this report:

 

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*Filed Herewith.

#Furnished herewith; not considered to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.

†Management contract or compensatory plan or arrangement required to be filed as an exhibit to this Annual Report on Form 10-K pursuant to Item 15(b).

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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.

 

 

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 February 19, 2015.