Table of Contents

 

 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-K

 

(Mark One)

 

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

 

For the fiscal year ended December 31, 2013

 

or

 

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

 

For the transition period from              to

 

Commission file number: 001-35779

 

USA Compression Partners, LP

(Exact Name of Registrant as Specified in its Charter)

 

Delaware

 

75-2771546

(State or Other Jurisdiction
of Incorporation or Organization)

 

(I.R.S. Employer
Identification No.)

 

100 Congress Avenue, Suite 450
Austin, TX

 

78701

(Address of Principal Executive Offices)

 

(Zip Code)

 

(512) 473-2662

(Registrant’s telephone number, including area code)

 

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

 

Title of each class

 

Name of each exchange on which registered

Common Units representing Limited Partner Interests

 

New York Stock Exchange

 

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

None

 

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

 

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

 

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

 

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 x    No o

 

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

 

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

 

Large accelerated filer o

 

Accelerated filer o

 

 

 

Non-accelerated filer x

 

Smaller reporting company o

(Do not check if a smaller reporting company)

 

 

 

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

 

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 28, 2013, the last business day of the registrant’s most recently completed second fiscal quarter was $258,535,875. This calculation does not reflect a determination that such persons are affiliates for any other purpose.

 

As of February 18, 2014, there were 24,034,240 common units and 14,048,588 subordinated units outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE: NONE

 

 

 



Table of Contents

 

Table of Contents

 

PART I

 

1

 

 

 

 

Item 1.

Business

1

 

Item 1A.

Risk Factors

12

 

Item 1B.

Unresolved Staff Comments

30

 

Item 2.

Properties

30

 

Item 3.

Legal Proceedings

30

 

Item 4.

Mine Safety Disclosures

30

 

 

 

PART II

 

30

 

 

 

 

Item 5.

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

30

 

Item 6.

Selected Financial Data

33

 

Item 7.

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

37

 

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

50

 

Item 8.

Financial Statements and Supplementary Data

50

 

Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

50

 

Item 9A.

Controls and Procedures

50

 

Item 9B.

Other Information

51

 

 

 

PART III

 

51

 

 

 

 

Item 10.

Directors, Executive Officers and Corporate Governance

51

 

Item 11.

Executive Compensation

57

 

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

64

 

Item 13.

Certain Relationships and Related Transactions, and Director Independence

67

 

Item 14.

Principal Accountant Fees and Services

69

 

 

 

PART IV

 

69

 

 

 

 

Item 15.

Exhibits and Financial Statement Schedules

69

 

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PART I

 

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

 

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

 

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

 

·                  changes in general economic conditions;

 

·                  competitive conditions in our industry;

 

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

 

·                  our ability to realize the anticipated benefits of acquisitions and to integrate the acquired assets with our existing fleet;

 

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

 

·                  changes in the availability and cost of capital;

 

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

 

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

 

·                  the effects of future litigation.

 

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

 

ITEM 1.        Business

 

References in this report to “USA Compression,” “we,” “our,” “us,” “the Partnership” or like terms refer to USA Compression Partners, LP and its wholly owned subsidiaries, including USA Compression Partners, LLC (“USAC Operating”) and USAC OpCo 2, LLC (“OpCo 2” and together with USAC Operating, the “Operating Subsidiaries”). References to “USA Compression Holdings” refer to USA Compression Holdings, LLC, the owner of USA Compression GP, LLC, our general partner. References to our “general partner” refer to USA Compression GP, LLC. 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.

 

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Overview

 

We are a growth oriented Delaware limited partnership and, based on management’s significant experience in the industry, we believe that we are one of the largest independent providers of compression services in the U.S. in terms of total compression unit horsepower. We have been providing compression services since 1998. As of December 31, 2013, we had 1,202,374 horsepower in our fleet and approximately 180,000 horsepower on order for expected delivery primarily in the first half of 2014. Our primary focus is to provide compression services to our customers in connection with infrastructure applications. Natural gas compression is a mechanical process whereby natural gas is compressed to a smaller volume, resulting in higher pressure. This process has various applications, including both allowing for the transportation of the 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 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 Marcellus, Eagle Ford, Utica, Mississippi Lime, Granite Wash, Woodford, Barnett, Permian Basin, Haynesville and Fayetteville shales. Because the demand for our services is driven by production of natural gas and crude oil, we have focused our activities in areas of attractive growth, which are generally found in these shale and unconventional resource plays.  Further, we believe production in these areas will increase in the future. According to the Annual Energy Outlook 2013 (the “2013 Outlook”) prepared by the Energy Information Agency (“EIA”), natural gas production from shale formations is expected to increase from 34% of total U.S. natural gas production in 2011 to 50% of total U.S. natural gas production in 2040. In addition, the EIA forecasts in its 2013 Outlook that total domestic crude oil production will increase by 33% from 2011 to 2019, and more importantly, forecasts tight oil production to increase by 128% over the same time period. Not only are the production and transportation volumes in these and other shale plays increasing, the geological and reservoir characteristics are also particularly attractive for compression services. The changes in production volume and pressure of shale plays over time result in a wider range of compression requirements than in conventional basins. We believe we are well-positioned to meet these changing operating conditions as a result of the flexibility of our compression units. While our business focuses largely on compression services in shale plays, we also provide compression services in more mature conventional basins, including crude oil wells targeted by horizontal drilling techniques. Wells in conventional basins typically require increasing amounts of compression as they age and pressures decline. In addition, the continued development of horizontal drilling, particularly in crude oil wells, has allowed producers to produce incremental volumes of crude oil on attractive economic terms. Our gas lift fleet, critical to producing oil from horizontal wells, serves this growing market demand.

 

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. As of December 31, 2013, we estimate that approximately 89% of our revenue generating horsepower was deployed in infrastructure applications, including large-volume gathering systems, processing facilities, transportation applications and crude oil gas lift. The design flexibility of our units, particularly in midstream applications, allows us to enter into longer-term contracts where appropriate 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’ dynamic 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. From 2003 through 2013, our average horsepower utilization was over 90%, occurring throughout periods of volatile natural gas prices.

 

We provide compression services to our customers under fixed-fee contracts, with initial contract terms of up to five years for midstream applications and six to twelve months for crude oil gas lift applications. We typically continue to provide compression services to our customers beyond their initial contract terms, either through contract renewals or on a month-to-month basis. We generally 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.

 

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Business Strategies

 

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

 

·                  Capitalize on the increased need for natural gas compression in conventional and unconventional plays. We expect additional demand for compression services to result from the continuing shift of natural gas production to domestic shale plays as well as the declining production pressures of aging conventional basins. In addition, the continued development of horizontal drilling in crude oil production and the demand for artificial lift techniques represents an attractive growth area. Our fleet of modern, flexible compression units, which are capable of being rapidly deployed and redeployed and many of which are designed to operate in multiple compression stages, will enable us to capitalize on these opportunities both in emerging shale plays as well as conventional fields.

 

·                  Continue to execute on attractive organic growth opportunities. Between 2003 and 2013, we grew the horsepower in our fleet of compression units and our compression revenues at a compound annual growth rate of 24%, primarily through organic growth. We believe organic growth opportunities will continue to be our most attractive source of near-term growth. We seek to achieve continued organic growth by (i) increasing our business with existing customers, (ii) obtaining new customers in our existing areas of operations and (iii) expanding our operations into new geographic areas.

 

·                  Partner with customers who have significant compression needs. We actively seek to identify customers with major acreage positions in active and growing areas. We work with these customers to jointly develop long-term and adaptable solutions designed to optimize their lifecycle compression costs. We believe this is important in determining the overall economics of producing, gathering and transporting natural gas. Our proactive and collaborative approach positions us to serve as our customers’ compression provider of choice.

 

·                  Pursue accretive acquisition opportunities. While our principal growth strategy will be to continue to grow organically, we may pursue accretive acquisition opportunities, including the acquisition of complementary businesses, participation in joint ventures or purchase of compression units from existing or new customers in conjunction with providing compression services to them. We will consider opportunities that (i) are in our existing geographic areas of operations or new, high-growth regions, (ii) meet internally established economic thresholds and (iii) may be financed on reasonable terms.

 

·                  Maintain financial flexibility. We intend to maintain financial flexibility to be able to take advantage of growth opportunities. Historically, we have utilized our cash flow from operations, borrowings under available debt facilities and operating leases to fund capital expenditures to expand our compression services business. This approach has allowed us to significantly grow our fleet and the amount of cash we generate, while maintaining our debt at levels we believe are manageable for our business. We believe our financial flexibility positions us to take advantage of future growth opportunities without incurring debt beyond appropriate levels.

 

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 our compression fleet and do not service third party owned equipment. We seek to enter into service contracts with each of our customers. In connection with the S&R Acquisition (as defined below), we acquired contracts related to the active compressors in the fleet that were styled as rentals. We are in the process of converting these agreements into service contracts. We do not own any compression fabrication facilities.

 

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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 at December 31, 2013 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 3500 and 3600 engine classes, which range from 630 to 4,700 horsepower per unit. These larger horsepower units, defined as 400 horsepower per unit or greater, represented approximately 81.2% of our total horsepower (including compression units on order) as of December 31, 2013. In addition, a portion of our fleet consists of smaller horsepower units ranging from 84 horsepower to 240 horsepower that are primarily used in our gas lift operations. 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, 2013 (including additional new compression unit horsepower on order for delivery between January 2014 and November 2014):

 

Unit Horsepower

 

Fleet
Horsepower

 

Horsepower on
Order (1)

 

Total
Horsepower (2)

 

Percentage of
Total
Horsepower

 

<400

 

236,677

 

23,042

 

259,719

 

18.8

%

>400 <1,000

 

193,964

 

6,720

 

200,684

 

14.5

%

>1,000

 

771,733

 

150,095

 

921,828

 

66.7

%

Total

 

1,202,374

 

179,857

 

1,382,231

 

100.0

%

 


(1)         As of December 31, 2013, we had on order 179,857 horsepower, of which 149,092 horsepower is expected to be delivered between January 2014 and June 2014, and 30,765 horsepower is expected to be delivered between July 2014 and November 2014.

 

(2)         Comprised of 2,461 compression units, including 266 new compression units on order.

 

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

 

 

 

Successor

 

 

Predecessor

 

 

 

Year Ended

 

Percent

 

Year Ended

 

Percent

 

 

Year Ended

 

Percent

 

 

 

December 31,

 

Change

 

December 31,

 

Change

 

 

December 31,

 

Change

 

Operating Data (unaudited):

 

2013

 

2012

 

2013

 

2011

 

2012

 

 

2010

 

2011

 

Fleet horsepower(1) 

 

1,202,374

 

919,121

 

30.8

%

722,201

 

27.3

%

 

609,730

 

18.4

%

Total available horsepower(2) 

 

1,278,829

 

935,681

 

36.7

%

809,418

 

15.6

%

 

612,410

 

32.2

%

Revenue generating horsepower(3)

 

1,070,457

 

794,324

 

34.8

%

649,285

 

22.3

%

 

533,692

 

21.7

%

Average revenue generating horsepower(4) 

 

902,168

 

749,821

 

20.3

%

570,900

 

31.3

%

 

516,703

 

10.5

%

Revenue generating compression units

 

2,137

 

978

 

118.5

%

888

 

10.1

%

 

795

 

11.7

%

Average horsepower per revenue generating compression unit(5)

 

720

 

791

 

(9.0

)%

692

 

14.3

%

 

667

 

3.7

%

Horsepower utilization(6):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

At period end

 

94.1

%

92.8

%

1.4

%

95.7

%

(3.0

)%

 

91.8

%

4.2

%

Average for the period(7) 

 

93.8

%

94.5

%

(0.7

)%

92.3

%

2.4

%

 

92.6

%

(0.3

)%

 


(1)         Fleet horsepower is horsepower for compression units that have been delivered to us (and excludes units on order). As of December 31, 2013, we had approximately 180,000 horsepower on order with expected delivery primarily in the first half of 2014.

 

(2)         Total available horsepower is revenue generating horsepower under contract for which we are billing a customer, horsepower in our fleet that is under contract but is not yet generating revenue, horsepower not yet in our fleet that is under contract not yet generating revenue and that is subject to a purchase order, and idle horsepower. Total available horsepower excludes new horsepower on order for which we do not have a compression services contract.

 

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(3)         Revenue generating horsepower is horsepower under contract for which we are billing a customer.

 

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

 

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

 

(6)         Horsepower utilization is calculated as (i)(a) revenue generating horsepower plus (b) horsepower in our fleet that is under contract, but is not yet generating revenue plus (c) horsepower not yet in our fleet that is under contract not yet generating revenue and that is subject to a purchase order, divided by (ii) total available horsepower less idle horsepower that is under repair. Horsepower utilization based on revenue generating horsepower and fleet horsepower at each applicable period end was 89.0%, 86.4%, 89.9% and 87.5%, for the years ended December 31, 2013, 2012, 2011 and 2010, respectively.

 

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

 

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

 

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

 

Generally, we expect each of our compression units to undergo a major overhaul between service deployment cycles once every eight to ten years for our larger horsepower units (400 horsepower or greater) and on average every five years for smaller horsepower units. A major overhaul involves the periodic rebuilding of the unit to materially extend its economic useful life or to enhance the unit’s ability to fulfill broader or more diversified compression applications. Because our compression fleet is comprised of units of varying horsepower that have been placed into service with staggered initial on-line dates, we are able to schedule overhauls in a way to avoid excessive maintenance capital expenditures and minimize the revenue impact of downtime.

 

We believe that our customers, by outsourcing their compression requirements, can achieve higher compression runtimes, which translates into increased volume of either natural gas or crude oil production and therefore increases 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 ranging from 95% to 98%, depending on field level requirements. 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.

 

General Compression Service Contract Terms

 

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

 

Term and termination. Our contracts typically have an initial term between one and five years for midstream applications and between six and twelve months for gas lift applications. 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.

 

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Availability. Our contracts often provide a guarantee of specified availability. We define availability as the percentage of time in a given period that our compression services are being provided or are capable of being provided. Availability is reduced by instances of “down-time” that are attributable to anything other than events of force majeure or acts or failures to act by the customer. “Down-time” under our contracts usually begins when our services stop being provided and when we receive notice of the problem. Down-time due to scheduled maintenance is also excluded from our availability commitment. 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 is based.

 

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

 

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

 

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

 

Insurance. Our contracts typically provide that both we and our customers are required to carry general liability, 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 current needs related to services currently being provided and to determine the customer’s future compression services requirements. This ongoing communication allows us to quickly identify and respond to our customers’ compression requirements. We currently focus on geographic areas where we can achieve economies of scale through high density operations.

 

Customers

 

Our customers consist of more than 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, 2013 and 2012 was Southwestern Energy Corporation and its subsidiaries, or Southwestern Energy. Southwestern Energy accounted for 14.3% of our revenue for the year ended December 31, 2013 and 14.5% of our revenue for the year ended December 31, 2012. Our ten largest customers accounted for 49% and 54% of our revenue for the years ended December 31, 2013 and 2012, respectively.

 

Suppliers and Service Providers

 

The principal manufacturers of components for our natural gas compression equipment include Caterpillar, Inc., or Caterpillar, Cummins Inc., or Cummins, and Arrow Engine Company, or Arrow (for engines), Air-X-Changers and Air Cooled Exchangers (for coolers), and Ariel Corporation, GE Oil & Gas Gemini products and Arrow (for compressor frames and cylinders). We also rely primarily on three vendors, A G Equipment Company, Standard Equipment Corp. and S&R Compression, LLC (“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

 

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standardized nature of our fleet. We have not experienced any material supply problems to date, although lead-times for Caterpillar engines and 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 by Caterpillar. Please read “— 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 current availability of attractive financing terms from financial institutions and equipment manufacturers makes the purchase of individual compression units increasingly affordable to our customers. We believe that we compete effectively on the basis of price, equipment availability, customer service, flexibility in meeting customer needs, quality and reliability of our compressors and related services.

 

Seasonality

 

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

 

Insurance

 

We believe that our insurance coverage is customary for the industry and adequate for our business. As is customary in the natural gas services industry, we review our safety equipment and procedures and carry insurance against most, but not all, risks of our business. Losses and liabilities not covered by insurance would increase our costs. The compression business can be hazardous, involving unforeseen circumstances such as uncontrollable flows of gas or well fluids, fires and explosions or environmental damage. To address the hazards inherent in our business, we maintain insurance coverage that, 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.

 

Environmental and Safety Regulations

 

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

 

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

 

Air emissions. The Clean Air Act, or 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 typically provides that the customer is responsible for obtaining air emissions permits and assuming the environmental risks related to site operations. Increased obligations of operators to reduce air emissions of nitrogen oxides and other pollutants from internal combustion engines in transmission service have been enacted by governmental authorities. For example, on August 20, 2010, the EPA published new regulations under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocal internal combustion engines, also known as Quad Z regulations. On June 7, 2012, the EPA proposed amendments to the final rule in response to several petitions for reconsideration. The EPA finalized the amendments on January 30, 2013. The rule requires us to undertake certain expenditures and activities, including purchasing and installing emissions control equipment on certain compressor engines and generators. The final rule became effective on April 1, 2013, and imposed varying compliance deadlines based on engine rating and type of site, with the latest deadlines falling on October 19, 2013. We do not believe the final rule has an impact on our operations and we do not believe that the costs associated with compliance with the final rule will be material.

 

On June 7, 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 on January 30, 2013 and were effective April 1, 2013. These recent modifications are not expected to impose material unbudgeted costs on operations.  The modifications seem to primarily make minor adjustments to the existing program that would not appear to add significant compliance costs.

 

In March 2008, the EPA also promulgated a new, lower National Ambient Air Quality Standard, or NAAQS, for ozone that was recently upheld in federal court. Under the CAA, the EPA was required to review recent scientific findings related to ground level ozone in 2013 and may issue a new NAAQS. However, a new standard has not yet been proposed. In addition, on January 15, 2013, the EPA promulgated a final rule revising the annual standard for PM 2.5 by lowering the level from 15 to 12 micrograms per cubic meter. The EPA does not anticipate making initial attainment or nonattainment designations until December 2014. 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 could impact our customers’ operations and increase the cost of additions to property, plant and equipment.

 

On April 17, 2012, the EPA finalized rules that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package included New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The rules establish specific new requirements regarding emissions from compressors and controllers at natural gas processing plants, dehydrators, storage tanks and other production equipment 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. On August 5, 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. These rules may require a number of modifications to our operations, including the installation of new equipment to control emissions from our compressors at initial startup. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

 

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

 

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

 

Climate change. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas, are examples of greenhouse gases. 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 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.  On October 15, 2013, the United States Supreme Court agreed to hear arguments regarding the Tailoring Rule during its 2013-2014 session. However, the Court refused to consider other issues such as whether greenhouse gases endanger public health. A decision is expected in this case by the end of June 2014.

 

Finally, on January 8, 2014, the EPA published standards of performance for greenhouse gas emissions from 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 are due March 10, 2014.

 

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.

 

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Water discharge. The Clean Water Act, or CWA, and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. The CWA also requires the development and implementation of spill prevention, control and countermeasures, including the construction and maintenance of containment berms and similar structures, if required, to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak at such facilities. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. Our compression operations do not generate process wastewaters that are discharged to waters of the U.S. In any event, our customers assume responsibility under 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 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 are anticipated to be available in 2014. The EPA also has recently announced that it believes hydraulic fracturing using fluids containing diesel fuel can be regulated under the SDWA notwithstanding the SDWA’s general exemption for hydraulic fracturing. Several states have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. We cannot predict the future of such legislation and what additional, if any, provisions would be. If additional levels of regulation, restrictions and permits were required through the adoption of new laws and regulations at the federal or state level, that could lead to delays, increased operating costs and process prohibitions that could reduce demand for our compression services, which would materially adversely affect our revenue and results of operations.

 

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

 

Site remediation. The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, and comparable state laws impose strict, joint and several liability without regard to fault or the legality of the original conduct on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include the owner and operator of a disposal site where a hazardous substance release occurred and any company that transported, disposed of or arranged for the transport or disposal of hazardous substances released at the site. Under CERCLA, such persons may be liable for the costs of remediating the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. In addition, where contamination may be present, it is not uncommon for the neighboring landowners and 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 placed on properties owned or leased by third party customers and operated by us pursuant to terms set forth in the natural gas compression services contracts executed by those customers. Under most of our natural gas compression services contracts, our customers must contractually indemnify us for certain damages we may suffer as a result of the release into the environment of hazardous and toxic substances. We are not currently responsible for any remedial activities at any properties used by us; however, there is always the possibility that our future use of those properties may result in spills or releases of petroleum hydrocarbons, wastes or other regulated substances into the environment that may cause us to become subject to remediation costs and liabilities under CERCLA, RCRA or other environmental laws. We cannot provide any assurance that the costs and liabilities associated with the future imposition of such remedial obligations upon us would not have a material adverse effect on our operations or financial position.

 

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

 

Properties

 

We do not currently own or lease any material facilities or properties for storage or maintenance of our compression units. As of December 31, 2013, our headquarters consisted of 11,307 square feet of leased space located at 100 Congress Avenue, Austin, Texas 78701.

 

Employees

 

USAC Management, a wholly owned subsidiary of our general partner, operates our assets and performs other administrative services for us, such as accounting, corporate development, finance and legal.  All of our employees, including our executives, are employees of USAC Management. As of December 31, 2013, USAC Management had 360 full time employees. None of our employees are subject to collective bargaining agreements. We consider our employee relations to be good.

 

Legal Proceedings

 

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

 

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 Report 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, 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 that the Partnership files with the SEC 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 $0.48 per unit per quarter, or $1.92 per unit per year, we will require available cash of $18.7 million per quarter, or $74.6 million per year, based on the number of common units, subordinated units and the 2.0% general partner interest currently outstanding at February 18, 2014. Under our cash distribution policy, the amount of cash we can distribute to our unitholders principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

 

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

 

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

 

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

 

·                  the level of competition from other companies; and

 

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

 

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

 

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

 

·                  the level of our operating costs and expenses;

 

·                  our debt service requirements and other liabilities;

 

·                  fluctuations in our working capital needs;

 

·                  restrictions contained in our revolving credit facility;

 

·                  the cost of acquisitions, if any;

 

·                  fluctuations in interest rates;

 

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

 

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

 

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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 to our unitholders.

 

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

 

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

 

We provide compression services under contracts with several key customers. The loss of one of these key customers may have a greater effect on our financial results than for a company with a more diverse customer base. Our largest customer for the years ended December 31, 2013 and 2012 was Southwestern Energy Company and its subsidiaries, or Southwestern Energy. Southwestern Energy accounted for 14.3% of our revenue for the year ended December 31, 2013 and 14.5% of our revenue for the year ended December 31, 2012. Our ten largest customers accounted for 49% and 54% of our revenue for the years ended December 31, 2013 and 2012, respectively. The loss of all or even a portion of the compression services we provide to our key customers, as a result of competition or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

 

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

 

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

 

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

 

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

 

Our customers may choose to vertically integrate their operations by purchasing and operating their own compression fleet, 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. Currently, the availability of attractive financing terms from financial institutions and equipment manufacturers facilitates this possibility by making the purchase of individual compression units increasingly affordable to our customers. 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

 

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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 ability to make cash distributions to our unitholders.

 

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

 

As of December 31, 2013, approximately 38% of our compression services on a horsepower basis (and 43% on a revenue basis for the year ended December 31, 2013) were provided on a month-to-month basis to customers who continue to utilize our services following expiration of the primary term of their contracts with us. These customers can generally terminate their month-to-month compression services contracts on 30-days’ written notice. If a significant number of these customers were to terminate their month-to-month services, or attempt to renegotiate their month-to-month contracts at substantially lower rates, it could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

 

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

 

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

 

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

 

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

 

·                  recruit and train qualified personnel and retain valued employees;

 

·                  expand our geographic presence;

 

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

 

·                  consummate accretive acquisitions;

 

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

 

·                  meet customer specific contract requirements or pre-qualifications.

 

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

 

We may be unable to grow successfully through 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.

 

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

 

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

 

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

 

We have an $850 million revolving credit facility that matures on December 13, 2018. In addition, we have the option to increase the amount of total commitments under the revolving credit facility by $100 million, subject to receipt of lender commitments and satisfaction of other conditions. As of December 31, 2013, we had outstanding borrowings of $420.9 million and available borrowings of $264.6 million, based on our borrowing base. Our ability to incur additional debt is subject to limitations in our revolving credit facility. Our level of debt could have important consequences to us, including the following:

 

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

 

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

 

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

 

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. In addition, our ability to service our debt under the revolving credit facility 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 satisfactory terms, or at all.

 

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

 

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

 

·                  grant liens;

 

·                  make certain loans or investments;

 

·                  incur additional indebtedness or guarantee other indebtedness;

 

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·                  enter into transactions with affiliates;

 

·                  merge or consolidate;

 

·                  sell our assets; or

 

·                  make certain acquisitions.

 

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 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. 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 $85.9 million of other intangible assets as of December 31, 2013. 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 (“GAAP”) requires us to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. Any event that causes a reduction in demand for our services could result in a reduction of our estimates of future cash flows and growth rates in our business. These events could cause us to record impairments of goodwill or other intangible assets. If we determine that any of our goodwill or other intangible assets are impaired, we will be required to take an immediate charge to earnings with a corresponding reduction of partners’ capital resulting in an increase in balance sheet leverage as measured by debt to total capitalization. There was no impairment recorded for goodwill or other intangible assets for the years ended December 31, 2013 and 2012.

 

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 if energy industry market conditions continue to be positive. When general industry conditions are good, the competition for experienced operational and field technicians increases as other energy and manufacturing companies’ needs for the same personnel increases. Our ability to grow or even to continue our current level of service to our current customers 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, Cummins and Arrow (for engines), Air-X-Changers and Air Cooled Exchangers (for coolers), and Ariel Corporation, GE Oil & Gas Gemini products and Arrow (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 three vendors, A G Equipment Company, Standard Equipment Corp. and S&R, to package and assemble our compression units. We do not

 

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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 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.

 

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

 

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

 

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

 

In August 2010, the U.S. Environmental Protection Agency, or the EPA, published new regulations under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocating internal combustion engines. 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 April, 2013, and imposes varying compliance deadlines based on engine ratings and type of site, with the latest deadlines falling during October 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 ability to make cash distributions to our unitholders could be impacted.

 

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In April 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, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The rules establish specific new requirements regarding emissions from compressors and controllers at natural gas processing plants, dehydrators, storage tanks and other production equipment 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 August 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. These rules may require a number of modifications to our operations, including the installation of new equipment to control emissions from our compressors at initial startup. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

 

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

 

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

 

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

 

Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas, are examples of greenhouse gases. 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. On 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 on 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.

 

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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.  On October 15, 2013, the United States Supreme Court agreed to hear arguments regarding the Tailoring Rule during its 2013-2014 session. However, the Court refused to consider other issues such as whether greenhouse gases endanger public health. A decision is expected in this case by the end of June 2014.

 

Finally, on January 8, 2014, the EPA published standards of performance for greenhouse gas emissions from 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.

 

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 Safe Drinking Water Act, or SDWA, to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the 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 are anticipated to be available in 2014. The EPA also has recently announced that it believes hydraulic fracturing using fluids containing diesel fuel can be regulated under the SDWA notwithstanding the SDWA’s general exemption for hydraulic fracturing. Several states have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. We cannot predict if additional legislation will ever be enacted and if so, what its provisions would be. If additional levels of regulation, restriction and permits were required through the adoption of new laws and regulations at the federal or state level, that could lead to delays, increased operating costs and process prohibitions that could reduce demand for our compression services, which could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our unitholders.

 

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

 

Our operations are subject to inherent risks such as equipment defects, malfunction and failures, and natural disasters that can result in uncontrollable flows of gas or well fluids, fires and explosions. These risks could expose us to substantial liability for personal injury, death, property damage, pollution and other environmental damages. Our insurance may be inadequate to cover our liabilities. Further, insurance covering the risks we face or in the amounts we desire may not be available in the future or, if available, the premiums may not be commercially justifiable. If we were to incur substantial liability and such damages were not covered by insurance or were in excess of policy limits, or if we were to incur liability at a time when we are not able to obtain liability insurance, our business, results of operations and financial condition could be adversely affected. Please read Part I, Item 1, “Business—Our Operations—Environmental and Safety Regulations” for a description of how we are subject to federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of human health and environment.

 

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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 natural gas supplies and markets for natural gas and natural gas liquids and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.

 

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

 

In connection with the closing of our initial public offering, we became subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded partnership. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002, or Section 404. For example, Section 404(a) 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) for 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 completion of our initial public offering 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, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. USA Compression Holdings is the sole member of our general partner and will have the right to appoint our general partner’s entire board of directors, including its independent directors. If the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

 

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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:

 

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

 

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

 

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

 

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

 

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

 

·                  our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert to common units;

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

·                  whether to exercise its limited call right;

 

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

 

·                  whether to elect to reset target distribution levels; and

 

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

 

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

 

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

 

The unitholders are currently unable to remove our general partner because our general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 662/3% of all outstanding common and subordinated units voting together as a single class is required to remove our general partner. USA Compression Holdings owns an aggregate of 50.9% 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

 

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subordinated units or their affiliates (including the general partner and its affiliates) are voted in favor of that removal, all subordinated units will automatically be converted into common units. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud or willful misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

·                  the ratio of taxable income to distributions may increase;

 

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

 

·                  the market price of the common units may decline.

 

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

 

USA Compression Holdings holds an aggregate of 5,337,977 common units and 14,048,588 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and may convert earlier under certain circumstances. In addition, USA Compression Holdings may acquire additional common units in connection with our DRIP. We have agreed to provide USA Compression Holdings with certain registration rights for any common and subordinated units it owns. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

 

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

 

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result, you may be required to sell your common units at an undesirable time or price. You may also incur a tax liability upon a sale of your units. USA Compression Holdings owns an aggregate of approximately 22.2% 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 50.9% of our outstanding common units.

 

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

 

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:

 

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

 

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

 

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

 

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

 

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

 

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

 

Pursuant to 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, which would subject us to entity level taxation, then our cash available for distribution to our unitholders would be substantially reduced.

 

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

 

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

 

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

 

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

 

Changes in current state law may subject us to additional entity level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay Texas franchise tax each year at a maximum effective rate of 0.7% of our gross income apportioned to Texas in the prior year. Imposition of any similar taxes by any other state may substantially reduce the cash available for distribution to our unitholders and, therefore, negatively impact the value of an investment in our common units.

 

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

 

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

 

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

 

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

 

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

 

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this report or from the positions we take, and the IRS’s positions may ultimately be sustained.

 

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It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

 

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

 

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

 

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

 

Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be 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. Our counsel is unable to opine as to the validity of such filing positions. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

We will be considered to have technically terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one 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 thirteen states. Many of these states currently impose a personal income tax on individuals. Many of these states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may control assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. It is your responsibility to file all foreign, federal, state and local tax returns.

 

ITEM 1B.               Unresolved Staff Comments

 

None.

 

ITEM 2.                        Properties

 

We do not currently own or lease any material facilities or properties for storage or maintenance of our compression units. As of December 31, 2013, our headquarters consisted of 11,307 square feet of leased space located at 100 Congress Avenue, Austin, Texas 78701.

 

ITEM 3.                        Legal Proceedings

 

None.

 

ITEM 4.                        Mine Safety Disclosures

 

None.

 

PART II

 

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

 

Our Partnership Interests

 

As of February 18, 2014, we had outstanding 24,034,240 common units, 14,048,588 subordinated units, a 2% general partner interest and incentive distribution rights, or IDRs. As of February 18, 2014, USA Compression Holdings, LLC owned approximately 22.2% of our outstanding common units and 100% of our subordinated units. Our general partner currently owns a 2.0% general partner interest in us and all of our IDRs. As discussed below under “Selected Information from Our Partnership Agreement— General Partner Interest and IDRs,” the IDRs represent the right to receive increasing percentages, up to a maximum of 48%, of the cash we distribute from operating surplus (as defined below) in excess of $0.4888 per unit per quarter. Our common units, which represent limited partner interests in us, are listed on the New York Stock Exchange (“NYSE”) under the symbol “USAC.”

 

Our common units have been traded on the NYSE since January 15, 2013, and therefore, we have not set forth quarterly information with respect to the high and low prices for our common units for periods prior to that date. 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 18, 2014, was $26.23.

 

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Cash

 

 

 

 

 

 

 

 

 

Distribution

 

 

 

 

 

Price Range

 

Per Common

 

 

 

Period

 

High

 

Low

 

Unit

 

Date Paid

 

 

 

 

 

 

 

 

 

 

 

First Quarter 2013(1)

 

$

20.00

 

$

17.25

 

$

0.348

(2)

May 14, 2013

 

Second Quarter 2013

 

$

23.72

 

$

18.77

 

$

0.44

 

August 14, 2013

 

Third Quarter 2013

 

$

26.50

 

$

22.50

 

$

0.46

 

November 14, 2013

 

Fourth Quarter 2013

 

$

27.12

 

$

22.07

 

$

0.48

 

February 14, 2014

 

 


(1)         Beginning on January 15, 2013 the first day our common units were traded on the NSYE.

(2)         Prorated to reflect 72 days of a quarterly cash distribution rate of $0.435 per unit.

 

Holders

 

At the close of business on February 18, 2014, we had 27 holders of record of our common units. The number of record holders does not include holders of shares in “street names” or persons, partnerships, associations, corporations or other entities identified in security position listings maintained by depositories.

 

Selected Information from our Partnership Agreement

 

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

 

Available Cash

 

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

 

Minimum Quarterly Distribution

 

Our partnership agreement provides that, during the subordination period, the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.425 per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units. On January 23, 2014, the Partnership announced a cash distribution of $0.48 per unit on its common and subordinated units. This fourth quarter distribution corresponds to an annualized distribution rate of $1.92 per unit. The distribution was paid on February 14, 2014 to unitholders of record as of the close of business on February 4, 2014. USA Compression Holdings, and Argonaut Private Equity, L.L.C. (“Argonaut”) and certain other related unitholders elected to reinvest all of this distribution with respect to their units pursuant to the Partnership’s Distribution Reinvestment Plan (“DRIP”). Following the issuance of common units under the DRIP, USAC Compression Holdings owned 50.9% of the Partnership’s outstanding limited partner interests, and Argonaut and the related parties participating in the DRIP, owned 19.4% of the Partnership’s outstanding limited partner interests.

 

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General Partner Interest and IDRs

 

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

 

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

 

Issuer Purchases of Equity Securities

 

None.

 

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

 

On January 18, 2013, we completed our IPO of common units pursuant to a Registration Statement on Form S-1, as amended (Reg. No. 333-174803), that was declared effective on January 14, 2013. Under the registration statement, we sold an aggregate of 11,000,000 common units at a price to the public of $18.00 per common unit. Barclays Capital Inc. and Goldman, Sachs & Co. acted as joint book-running managers of the offering. The offering closed on January 18, 2013. As a result of our IPO, we raised a total of $198.0 million in gross proceeds, and approximately $180.5 million in net proceeds after deducting underwriting discounts and commissions of $12.2 million, structuring fees of $0.7 million and offering expenses of $4.6 million.

 

On August 30, 2013, in connection with the acquisition from S&R of certain assets and liabilities related to the business of providing compression services to third parties engaged in the exploration, production, gathering, processing, transportation or distribution of oil and gas (the “S&R Acquisition”), the Partnership issued 7,425,261 common units to certain accredited investors (the “Holders”) who are members or beneficial owners of S&R or its controlling member, Argonaut Private Equity, L.L.C. (“Argonaut”).

 

The common units issued in connection with the S&R Acquisition were issued in a private placement in reliance upon an exemption from the registration requirements of the Securities Act, pursuant to Section 4(a)(2) thereof. In connection with the S&R Acquisition, we entered into a registration rights agreement with Argonaut and the other Holders pursuant to which we agreed to register the common units issued in connection with the S&R Acquisition. On February 3, 2014, we filed a Registration Statement on Form S-3 (File No. 333-193724) (the “S-3 Registration Statement”).  Until such time as the S-3 Registration Statement is declared effective by the SEC, the common units issued in connection with the S&R Acquisition may not be offered or sold in the United States absent an applicable exemption from the registration requirements of the Securities Act and applicable state securities laws.

 

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 Stockholder Matters” of this report.

 

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ITEM 6.                        Selected Financial Data

 

SELECTED HISTORICAL FINANCIAL DATA

 

In the table below we have presented certain selected financial data for USA Compression Partners, LP for each of the five years in the period ended December 31, 2013, which has been derived from our audited consolidated financial statements. The following information should be read together with Management’s Discussion and Analysis of Financial Condition and Results of Operations and the Financial Statements contained in Item 7 of this report.

 

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

 

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

 

 

 

Successor(1)

 

 

Predecessor

 

 

 

Years ended December 31,

 

 

Years ended December 31,

 

 

 

2013

 

2012

 

2011

 

 

2010

 

2009

 

 

 

(in thousands)

 

 

(in thousands)

 

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

Contract operations

 

$

150,360

 

$

116,373

 

$

93,896

 

 

$

89,785

 

$

93,178

 

Parts and service

 

2,558

 

2,414

 

4,824

 

 

2,243

 

2,050

 

Total revenues

 

152,918

 

118,787

 

98,720

 

 

92,028

 

95,228

 

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

Cost of operations

 

48,097

 

37,796

 

39,605

 

 

33,292

 

30,096

 

Selling, general and administrative

 

27,587

 

18,269

 

12,726

 

 

11,370

 

9,136

 

Restructuring charges(2)

 

 

 

300

 

 

 

 

Depreciation and amortization

 

52,917

 

41,880

 

32,738

 

 

24,569

 

22,957

 

(Gain) loss of sale of assets

 

284

 

266

 

178

 

 

(90

)

(74

)

Impairment of compression equipment

 

203

 

 

 

 

 

1,677

 

Total costs and expenses

 

129,088

 

98,211

 

85,547

 

 

69,141

 

63,792

 

Operating income

 

23,830

 

20,576

 

13,173

 

 

22,887

 

31,436

 

Other income (expense):

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

(12,488

)

(15,905

)

(12,970

)

 

(12,279

)

(10,043

)

Other

 

9

 

28

 

21

 

 

26

 

25

 

Total other expense

 

(12,479

)

(15,877

)

(12,949

)

 

(12,253

)

(10,018

)

Income before income tax expense

 

11,351

 

4,699

 

224

 

 

10,634

 

21,418

 

Income tax expense(3)

 

280

 

196

 

155

 

 

155

 

190

 

Net income

 

$

11,071

 

$

4,503

 

$

69

 

 

$

10,479

 

$

21,228

 

Adjusted EBITDA

 

$

81,130

 

$

63,484

 

$

51,285

 

 

$

51,987

 

$

56,917

 

Other Financial Data:

 

 

 

 

 

 

 

 

 

 

 

 

Capital expenditures(4)

 

$

159,547

 

$

179,977

 

$

133,264

 

 

$

18,886

 

$

29,580

 

Cash flows provided by (used in):

 

 

 

 

 

 

 

 

 

 

 

 

Operating activities

 

68,190

 

41,974

 

33,782

 

 

38,572

 

42,945

 

Investing activities

 

(153,946

)

(178,589

)

(140,444

)

 

(18,768

)

(26,763

)

Financing activities

 

85,756

 

136,619

 

106,662

 

 

(19,804

)

(16,545

)

 

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Table of Contents

 

 

 

Successor(1)

 

 

Predecessor

 

 

 

Years ended December 31,

 

 

Years ended December 31,

 

 

 

2013

 

2012

 

2011

 

 

2010

 

2009

 

 

 

(in thousands)

 

 

(in thousands)

 

Balance Sheet Data (at period end):

 

 

 

 

 

 

 

 

 

 

 

 

Working capital(5)

 

$

(24,177

)

$

(12,076

)

$

(11,295

)

 

$

(3,984

)

$

(4,678

)

Total assets

 

1,185,884

 

872,645

 

727,876

 

 

614,718

 

352,757

 

Long-term debt

 

420,933

 

502,266

 

363,773

 

 

255,491

 

260,470

 

Partners’ equity

 

707,727

 

343,526

 

339,023

 

 

338,954

 

72,626

 

 


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

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

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

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

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

 

Non-GAAP Financial Measures

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

 

 

Successor(1)

 

 

Predecessor

 

 

 

Years ended December 31,

 

 

Years ended December 31,

 

 

 

2013

 

2012

 

2011

 

 

2010

 

2009

 

 

 

(in thousands)

 

 

(in thousands)

 

Net income

 

$

11,071

 

$

4,503

 

$

69

 

 

$

10,479

 

$

21,228

 

Interest expense

 

12,488

 

15,905

 

12,970

 

 

12,279

 

10,043

 

Depreciation and amortization

 

52,917

 

41,880

 

32,738

 

 

24,569

 

22,957

 

Income taxes

 

280

 

196

 

155

 

 

155

 

190

 

Impairment of compression equipment(2)

 

203

 

 

 

 

 

1,677

 

Unit-based compensation expense

 

1,343

 

 

 

 

382

 

269

 

Equipment operating lease expense(3)

 

 

 

4,053

 

 

2,285

 

553

 

Riverstone management fee(4)

 

49

 

1,000

 

1,000

 

 

 

 

Restructuring charges(5)

 

 

 

300

 

 

 

 

Fees and expenses related to the Holdings Acquisition(6)

 

 

 

 

 

1,838

 

 

Transaction expenses for S&R Acquisition (7)

 

2,142

 

 

 

 

 

 

Other

 

637

 

 

 

 

 

 

Adjusted EBITDA

 

$

81,130

 

$

63,484

 

$

51,285

 

 

$

51,987

 

$

56,917

 

Interest expense

 

(12,488

)

(15,905

)

(12,970

)

 

(12,279

)

(10,043

)

Income tax expense

 

(280

)

(196

)

(155

)

 

(155

)

(190

)

Equipment operating lease expense(3)

 

 

 

(4,053

)

 

(2,285

)

(553

)

Unit-based compensation expense

 

(1,343

)

 

 

 

(382

)

(269

)

Riverstone management fee(4)

 

(49

)

(1,000

)

(1,000

)

 

 

 

Restructuring charges(5)

 

 

 

(300

)

 

 

 

Impairment of compression equipment(2)

 

(203

)

 

 

 

 

(1,677

)

Fees and expenses related to the Holdings Acquisition(6)

 

 

 

 

 

(1,838

)

 

Transaction expenses for S&R Acquisition(7)

 

(2,142

)

 

 

 

 

 

Other

 

3,386

 

(58

)

(920

)

 

3,744

 

2,234

 

Changes in operating assets and liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

Accounts receivable and advance to employee

 

(11,675

)

169

 

(976

)

 

(336

)

1,865

 

Inventory

 

(5,725

)

(1,004

)

1,974

 

 

503

 

(3,680

)

Prepaids

 

(601

)

(153

)

(219

)

 

(18

)

608

 

Other non-current assets

 

3,824

 

(1,315

)

(2,601

)

 

1

 

(4

)

Accounts payable

 

8,133

 

(5,340

)

1,987

 

 

(825

)

(857

)

Accrued liabilities and deferred revenue

 

6,223

 

3,292

 

1,730

 

 

455

 

(1,406

)

Net cash provided by operating activities

 

$

68,190

 

$

41,974

 

$

33,782

 

 

$

38,572

 

$

42,945

 

 


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

 

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

 

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

 

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(4)         Represents management fees paid to Riverstone for services performed during 2013, 2012 and 2011. As these fees are not paid by us as a public company, we believe it is useful to investors to view our results excluding these fees.

 

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

 

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

 

(7)         Represents S&R transaction expenses incurred during the third and fourth quarter of 2013. As these fees are not recurring, the Partnership believes it is useful to investors to view its results excluding these fees.

 

We define distributable cash flow as net income (loss) plus non-cash interest expense, depreciation and amortization expense, impairment of compression equipment charges, and non-cash SG&A costs, less maintenance capital expenditures. We define adjusted distributable cash flow as distributable cash flow plus certain one-time transaction expenses for the S&R Acquisition. We believe distributable cash flow and adjusted distributable cash flow are an 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) to the cash distributions we expect to pay our unitholders. Using distributable cash flow and adjusted distributable cash flow, management can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Our distributable cash flow may not be comparable to a similarly titled measure of another company because other entities may not calculate distributable cash flow in the same manner.

 

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

 

The following table reconciles our net income to distributable cash flow and adjusted distributable cash flow for each of the periods presented (in thousands):

 

 

 

Successor(1)

 

 

Predecessor

 

 

 

Years Ended December 31,

 

 

Years Ended December 31,

 

 

 

2013

 

2012

 

2011

 

 

2010

 

2009

 

Net income

 

$

11,071

 

$

4,503

 

$

69

 

 

$

10,479

 

$

21,228

 

Plus: Non-cash interest expense

 

2,201

 

1,855

 

(1,057

)

 

3,449

 

363

 

Plus: Depreciation and amortization

 

52,917

 

41,880

 

32,738

 

 

24,569

 

22,957

 

Plus: Unit-based compensation expense

 

1,343

 

 

 

 

382

 

269

 

Plus: Impairment of compression equipment

 

203

 

 

 

 

 

1,677

 

Less: Maintenance capital expenditures(2)

 

14,304

 

13,310

 

8,961

 

 

13,018

 

9,354

 

Distributable cash flow

 

$

53,431

 

$

34,928

 

$

22,789

 

 

$

25,861

 

$

37,140

 

Transaction expenses for S&R Acquisition and other(3)

 

2,779

 

 

 

 

 

 

Adjusted distributable cash flow

 

$

56,210

 

$

34,928

 

$

22,789

 

 

$

25,861

 

$

37,140

 

 


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

 

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

 

(3)         Reflects $2.1 million of transaction expenses for the S&R Acquisitions and $0.7 million of nonrecurring expenses, for 2013.

 

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Table of Contents

 

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

 

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

 

Overview

 

We are a growth oriented Delaware limited partnership and, based on management’s significant experience in the industry, we believe that we are one of the largest independent providers of compression services in the U.S. in terms of total compression unit horsepower. We have been providing compression services since 1998. As of December 31, 2013, we had 1,202,374 horsepower in our fleet and approximately 180,000 horsepower on order for expected delivery primarily in the first half of 2014. Our primary focus is to provide compression services to our customers in connection with infrastructure applications. Natural gas compression is a mechanical process whereby natural gas is compressed to a smaller volume, resulting in higher pressure. This process has various applications, including both allowing for the transportation of the 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 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 Marcellus, Eagle Ford, Utica, Mississippi Lime, Granite Wash, Woodford, Barnett, Permian Basin, Haynesville and Fayetteville shales. Because the demand for our services is driven by production of natural gas and crude oil, we have focused our activities in areas of attractive growth, which are generally found in these shale and unconventional resource plays.  Further, we believe production in these areas will increase in the future. According to the 2013 Outlook prepared by the EIA, natural gas production from shale formations is expected to increase from 34% of total U.S. natural gas production in 2011 to 50% of total U.S. natural gas production in 2040. In addition, the EIA forecasts in its 2013 Outlook that total domestic crude oil production will increase by 33% from 2011 to 2019, and more importantly, forecasts tight oil production to increase by 128% over the same time period.  Not only are the production and transportation volumes in these and other shale plays increasing, the geological and reservoir characteristics are also particularly attractive for compression services. The changes in production volume and pressure of shale plays over time result in a wider range of compression requirements than in conventional basins. We believe we are well-positioned to meet these changing operating conditions as a result of the flexibility of our compression units. While our business focuses largely on compression services in shale plays, we also provide compression services in more mature conventional basins, including crude oil wells targeted by horizontal drilling techniques. Wells in conventional basins typically require increasing amounts of compression as they age and pressures decline. In addition, the continued development of horizontal drilling, particularly in crude oil wells, has allowed producers to produce incremental volumes of crude oil on attractive economic terms. Our gas lift fleet, critical to producing oil from horizontal wells, serves this growing market demand.

 

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

 

We provide compression services to our customers under fixed-fee contracts, with initial contract terms of up to five years for midstream applications and six to twelve months for crude oil gas lift applications. We typically continue to provide compression services to our customers beyond their initial contract terms, either through contract renewals or on a month-to-month basis. For the year ended December 31, 2013, approximately 38% of our compression services on a horsepower basis (and 43% on a revenue basis) were provided to customers under contracts continuing on a month to month basis. We generally 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

 

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Table of Contents

 

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 indirect exposure to short-term volatility in natural gas and crude oil commodity prices is mitigated by the long-term nature of the majority of our contracts. As of December 31, 2013, we estimate that approximately 89% of our revenue generating horsepower was deployed in infrastructure applications, including large volume gathering systems, processing facilities, transportation applications and crude oil gas lift.

 

General Trends and Outlook

 

Following a period of decreasing market rates in 2009 and 2010, when we elected to sign shorter-term contracts to limit our long-term exposure to lower market rates, rates have improved and generally stabilized starting in 2011 and continue improving throughout 2013.  We have experienced some pricing pressure on certain of our midstream compression units during 2013. However, over the long term, we expect that continued improved pricing will ultimately improve our average monthly revenue per revenue generating horsepower as contracts that we entered into in 2009 and early 2010 expire and we enter into new contracts at higher rates. In our gas lift fleet, we have continued to experience strong market demand and, as a result, attractive pricing. We intend to grow the number of midstream and gas lift units in our fleet. While larger horsepower units used in midstream applications in general allow us to generate higher gross operating margins than gas lift units, they also generate lower average monthly revenue per revenue generating horsepower.

 

Our ability to increase our revenues is dependent in large part on our ability to add new revenue generating compression units to our fleet and increase the utilization of idle compression units. During 2011, we began to see an increase in overall natural gas activity in the U.S. and experienced an increase in demand for our compression services that has continued through 2012 and 2013. The generally strong activity in crude oil production in our core gas lift regions has also contributed to increased demand for our services. Revenue generating horsepower increased by 34.8% from December 31, 2012 to December 31, 2013, in part due to the S&R Acquisition. Average revenue generating horsepower increased by 20.3%, primarily due to growth in our core midstream compression business along with the S&R Acquisition, from the year ended December 31, 2012 to the year ended December 31, 2013. We believe the natural gas activity levels in the U.S. will continue to increase in the foreseeable future, particularly in shale plays, with respect to natural gas, as well as crude oil. We anticipate this activity will result in higher demand for our compression services, which we believe should result in increasing revenues. However, the expected increase in overall natural gas and crude oil activity and demand for our compression services may not occur for a variety of reasons. Please read Part I, Item 1A. “Risk Factors — Risks Related to Our Business — A long-term reduction in the demand for, or production of, natural gas or crude oil in the locations where we operate could adversely affect the demand for our services or the prices we charge for our services, which could result in a decrease in our revenues and cash available for distribution to our 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 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. From April 2008 through December 2013, we redeployed approximately 66,900 horsepower of our compression units from our Central operating region to our Northeast operating region, which includes the Marcellus shale, to meet increasing customer demand in that geographic area.

 

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Table of Contents

 

Many of our customers have access to low-cost capital, made available by banks and equipment manufacturers, and have elected to access this capital to add compression units to their owned compression fleets. Additional purchases of compression equipment by our customers may result in reduced demand for our compression services by these customers, which could materially reduce our results of operations and ability to make cash distributions to our unitholders.

 

Supply and Demand for Natural Gas 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. The EIA forecasts in its 2013 Outlook that natural gas production in the U.S. is expected to increase by approximately 44% from 2011 to 2040. 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 short-term declines in natural gas prices have a short-term negative effect on the development activity in natural gas fields, periods of lower development activity tend to place emphasis on improving production efficiency. As a result of our commitment to providing a high level of availability of the equipment used to provide compression services, we believe our service run times position us to satisfy the needs of our customers.

 

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 forecasts in its 2013 Outlook that total domestic crude oil production will increase by 33% from 2011 to 2019, and more importantly, forecasts tight oil production to increase by 128% over the same time period.  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.

 

Access to External Expansion Capital

 

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

 

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Table of Contents

 

Operating Highlights

 

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

 

 

 

Year Ended
December 31,

 

Percent Change

 

Operating Data (unaudited):

 

2013

 

2012

 

2011

 

2013

 

2012

 

Fleet horsepower(1)

 

1,202,374

 

919,121

 

722,201

 

30.8

%

27.3

%

Total available horsepower(2)

 

1,278,829

 

935,681

 

809,418

 

36.7

%

15.6

%

Revenue generating horsepower(3)

 

1,070,457

 

794,324

 

649,285

 

34.8

%

22.3

%

Average revenue generating horsepower(4)

 

902,168

 

749,821

 

570,900

 

20.3

%

31.3

%

Average revenue per revenue generating horsepower per month

 

$

14.15

 

$

13.39

 

$

14.07

 

5.7

%

(4.8

)%

Revenue generating compression units

 

2,137

 

978

 

888

 

118.5

%

10.1

%

Average horsepower per revenue generating compression unit(5)

 

720

 

791

 

692

 

(9.0

)%

14.3

%

Horsepower utilization(6):

 

 

 

 

 

 

 

 

 

 

 

At period end

 

94.1

%

92.8

%

95.7

%

1.4

%

(3.0

)%

Average for the period(7)

 

93.8

%

94.5

%

92.3

%

(0.7

)%

2.4

%

 


(1)         Fleet horsepower is horsepower for compression units that have been delivered to us (and excludes units on order). As of December 31, 2013, we had approximately 180,000 horsepower on order for delivery which is expected to be delivered primarily in the first half of 2014.

 

(2)         Total available horsepower is revenue generating horsepower under contract for which we are billing a customer, horsepower in our fleet that is under contract but is not yet generating revenue, horsepower not yet in our fleet that is under contract not yet generating revenue and that is subject to a purchase order, and idle horsepower. Total available horsepower excludes new horsepower on order for which we do not have a compression services contract.

 

(3)         Revenue generating horsepower is horsepower under contract for which we are billing a customer.

 

(4)         Calculated as the average of the month-end revenue generating horsepower for each of the months in the period.

 

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

 

(6)         Horsepower utilization is calculated as (i)(a) revenue generating horsepower plus (b) horsepower in our fleet that is under contract, but is not yet generating revenue plus (c) horsepower not yet in our fleet that is under contract not yet generating revenue and that is subject to a purchase order, divided by (ii) total available horsepower less idle horsepower that is under repair. Horsepower utilization based on revenue generating horsepower and fleet horsepower at each applicable period end was 89.0%, 86.4% and 89.9%, for the years ended December 31, 2013, 2012 and 2011, respectively.

 

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

 

The increase in fleet horsepower as of December 31, 2013 compared to December 31, 2012 is attributable to the compression units added to our fleet to meet the incremental demand by new and current customers and the S&R Acquisition. Revenue generating horsepower increased by 34.8% from December 31, 2012 to December 31, 2013 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. The increase in fleet horsepower as of December 31, 2012 compared to December 31, 2011 is attributable to the compression units added to our fleet to meet the incremental demand by new and current customers. Revenue generating horsepower increased by 22.3% from December 31, 2011 to December 31, 2012, primarily due to organic growth and increasing customer demand. The average horsepower per revenue generating compression unit increased from 692 to 791 between 2011 and 2012, primarily due to our focus during that period on the addition of large horsepower compression units.

 

 

 

Year Ended December 31,

 

Percent Change

 

Other Financial Data:

 

2013

 

2012

 

2011

 

2013

 

2012

 

 

 

(in thousands)

 

Gross Operating Margin(1)

 

$

104,821

 

$

80,991

 

$

59,115

 

29.4

%

37.0

%

Gross operating margin percentage(2)

 

68.5

%

68.2

%

59.9

%

0.5

%

13.9

%

Adjusted EBITDA(3)

 

81,130

 

63,484

 

51,285

 

27.8

%

23.8

%

Adjusted EBITDA percentage(2)

 

53.1

%

53.4

%

51.9

%

(0.6

)%

2.9

%

 


(1)         Gross operating margin is a non-GAAP financial measure. We calculate gross operating margin as revenue less cost of operations, exclusive of depreciation and amortization expense. We believe that gross operating margin is useful as a supplemental measure of our operating profitability. Gross operating margin should not be considered an alternative to, or more meaningful than, operating income or any other measure of financial performance presented in accordance with GAAP. Moreover, gross operating margin as presented may not be comparable to similarly titled measures of other companies. Because we capitalize assets, depreciation and amortization of equipment is a necessary element of our costs. To compensate for the limitations of gross operating margin as a measure of our performance, we believe that it is important to consider operating income determined under GAAP, as well as gross operating margin, to evaluate our operating profitability. For more information, please read “Item 6 — Selected Historical Financial Data — Non-GAAP Financial Measures.”

 

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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:

 

 

 

Year Ended December 31,

 

 

 

2013

 

2012

 

2011

 

 

 

(in thousands)

 

Revenues:

 

 

 

 

 

 

 

Contract operations

 

$

150,360

 

$

116,373

 

$

93,896

 

Parts and service

 

2,558

 

2,414

 

4,824

 

Total revenues

 

152,918

 

118,787

 

98,720

 

Cost of operations, exclusive of depreciation and amortization

 

48,097

 

37,796

 

39,605

 

Gross operating margin

 

104,821

 

80,991

 

59,115

 

Other operating and administrative costs and expenses:

 

 

 

 

 

 

 

Selling, general and administrative

 

27,587

 

18,269

 

12,726

 

Restructuring charges

 

 

 

300

 

Depreciation and amortization

 

52,917

 

41,880

 

32,738

 

(Gain) loss on sale of assets

 

284

 

266

 

178

 

Impairment of compression equipment

 

203

 

 

 

Total other operating and administrative costs and expenses

 

80,991

 

60,415

 

45,942

 

Operating income

 

$

23,830

 

$

20,576

 

$

13,173

 

 

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

 

(3)         For a reconciliation of Adjusted EBITDA, a non-GAAP financial measure, to net income and cash flows from operating activities, its most directly comparable GAAP financial measures, see “Item 6 — Selected Historical Financial Data—Non-GAAP Financial Measures.”

 

Gross operating margin, as a percentage of total revenues, increased to 68.5% in 2013 from 68.2% in 2012. The increase in gross operating margin was primarily attributable to a 28.7% increase in total revenues when comparing the periods, partially offset by an increase of 27.3% in cost of operations. Average revenue generating horsepower increased from 749,821 in 2012 to 902,168 in 2013, an increase of 20.3%, primarily due to compression units added to our fleet to meet the incremental demand by new and current customers and the S&R Acquisition. Average revenue per revenue generating horsepower per month increased to $14.15 in 2013 from $13.39 in 2012, an increase of 5.7%. The increase in average revenue per revenue generating horsepower per month was primarily due to higher revenue per horsepower per month from the gas lift compression units that were acquired from S&R. The increase in cost of operations is primarily attributable to (1) a $2.8 million increase in lubrication oil expenses due to a 21.7% increase in gallons consumed, offset by a 3.9% decrease in the average supplier price per gallon, (2) a $4.3 million increase in direct labor expenses, (3) a $0.9 million increase in training and safety expense, (4) a $0.4 million increase in maintenance parts and (5) a $0.6 million increase related to vehicle tools and gasoline. These factors are attributable primarily to the increase in our fleet size due to organic growth and four months of operations related to the assets acquired in 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.

 

Gross operating margin, as a percentage of total revenues, increased to 68.2% in 2012 from 59.9% in 2011. The increase in gross operating margin percentage was primarily attributable to a 20.3% increase in total revenues when comparing the periods, and a 4.6% decrease in cost of operations. Average revenue generating horsepower increased from 570,900 in 2011 to 749,821 in 2012, an increase of 31.3%, primarily due to organic growth and increasing customer demand. Average revenue per revenue generating horsepower per month declined to $13.39 in 2012 from $14.07 in 2011, a decrease of 4.8%. The decline in average revenue per revenue generating horsepower per month related primarily to the 14.3% increase in average horsepower per revenue generating compression unit to 791 for 2012 from 692 in 2011, resulting from our focus on the addition of large horsepower compression units to our fleet. The decrease in cost of operations is attributable to a $4.1 million decrease in equipment operating lease expense, as the Caterpillar operating lease schedules were terminated on December 15, 2011. Partially offsetting the decrease related to the Caterpillar operating lease were certain cost increases, including (1) a $1.1 million increase in lubrication oil expenses due to both a 7.1% increase in the average supplier price per gallon and a 12.7% increase in gallons consumed, (2) a $1.0 million increase in direct labor expenses and (3) a $0.3 million increase related to vehicle tools and gasoline, all of which were attributable primarily to the increase in the size of our fleet.

 

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Table of Contents

 

Financial Results of Operations

 

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:

 

 

 

Year ended December 31,

 

Percent

 

 

 

2013

 

2012

 

Change

 

 

 

(in thousands)

 

 

 

Revenues:

 

 

 

 

 

 

 

Contract operations

 

$

150,360

 

$

116,373

 

29.2

%

Parts and service

 

2,558

 

2,414

 

6.0

%

Total revenues

 

152,918

 

118,787

 

28.7

%

Costs and expenses:

 

 

 

 

 

 

 

Cost of operations, exclusive of depreciation and amortization

 

48,097

 

37,796

 

27.3

%

Selling, general and administrative

 

27,587

 

18,269

 

51.0

%

Depreciation and amortization

 

52,917

 

41,880

 

26.4

%

(Gain) loss on sale of assets

 

284

 

266

 

6.8

%

Impairment of compression equipment

 

203

 

 

 

Total costs and expenses

 

129,088

 

98,211

 

31.4

%

Operating income

 

23,830

 

20,576

 

15.8

%

Other income (expense):

 

 

 

 

 

 

 

Interest expense

 

(12,488

)

(15,905

)

(21.5

)%

Other

 

9

 

28

 

(67.9

)%

Total other expense

 

(12,479

)

(15,877

)

(21.4

)%

Income before income tax expense

 

11,351

 

4,699

 

141.6

%

Income tax expense

 

280

 

196

 

42.9

%

Net income

 

$

11,071

 

$

4,503

 

145.9

%

 

Contract operations revenue. Contract operations revenue was $150.4 million for the year ended December 31, 2013 compared to $116.4 million in 2012, an increase of 29.2%. Average revenue generating horsepower increased from 749,821 for the year ended December 31, 2012 to 902,168 for the year ended December 31, 2013, an increase of 20.3%, primarily due to growth in our core midstream compression assets along with the addition of assets in connection with the S&R Acquisition. Average revenue per revenue generating horsepower per month increased from $13.39 for the year ended December 31, 2012 to $14.15 for the year ended December 31, 2013, an increase of 5.7%, primarily due to higher revenue per horsepower per month from the gas lift compression units that were acquired in the S&R Acquisition. There were 2,137 revenue generating compression units at December 31, 2013 compared to 978 at December 31, 2012, a 118.5% increase, primarily due to the S&R Acquisition and organic growth in our core midstream compression assets. Revenue generating horsepower was 1,070,457 at December 31, 2013 compared to 794,324 at December 31, 2012, a 34.8% increase, primarily due to growth in our core midstream compression assets along 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.

 

Cost of operations, exclusive of depreciation and amortization. Cost of operations was $48.1 million for the year ended December 31, 2013 compared to $37.8 million for the year ended December 31, 2012, an increase of 27.3%. The increase is primarily attributable to the increase in our fleet size. Certain cost increases consisted of (1) a $2.8 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 $4.3 million increase in direct labor expenses, (3) a $0.9

 

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Table of Contents

 

million increase in training and safety expense, (4) a $0.4 million increase in maintenance parts and (5) a $0.6 million increase related to vehicle tools and gasoline. These factors are primarily attributable to the increase in our fleet size due to organic growth and four months of operations related to the assets acquired in 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.

 

Selling, general and administrative expense. Selling, general and administrative expense was $27.6 million for the year ended December 31, 2013 compared to $18.3 million for the year ended December 31, 2012, an increase of 51.0%. Approximately $3.5 million of the increase in selling, general and administrative expense is 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 Partnership’s 2013 Long-Term Incentive Plan. Other significant increases included (1) a $0.6 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. 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 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. Depreciation and amortization expense was $52.9 million for the year ended December 31, 2013 compared to $41.9 million for the year ended December 31, 2012, an increase of 26.4%. The increase 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.

 

Interest expense. Interest expense was $12.5 million for the year ended December 31, 2013 compared to $15.9 million for the year ended December 31, 2012, a decrease of 21.5%. Included in interest expense is 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, for the year then ended, respectively. 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.

 

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

 

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

 

 

 

Successor

 

 

 

 

 

Year Ended December 31,

 

Percent

 

 

 

2012

 

2011

 

Change

 

 

 

(in thousands)

 

 

 

Revenues:

 

 

 

 

 

Contract operations

 

$

116,373

 

$

93,896

 

23.9

%

Parts and service

 

2,414

 

4,824

 

(50.0

)%

Total revenues

 

118,787

 

98,720

 

20.3

%

 

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Table of Contents

 

 

 

Successor

 

 

 

 

 

Year Ended December 31,

 

Percent

 

 

 

2012

 

2011

 

Change

 

Costs and expenses:

 

 

 

 

 

 

 

Cost of operations, exclusive of depreciation and amortization

 

37,796

 

39,605

 

(4.6

)%

Selling, general and administrative

 

18,269

 

12,726

 

43.6

%

Restructuring charges

 

 

300

 

 

 

Depreciation and amortization

 

41,880

 

32,738

 

27.9

%

(Gain) loss on sale of assets

 

266

 

178

 

49.4

%

Total costs and expenses

 

98,211

 

85,547

 

14.8

%

Operating income

 

20,576

 

13,173

 

56.2

%

Other income (expense):

 

 

 

 

 

 

 

Interest expense

 

(15,905

)

(12,970

)

22.6

%

Other

 

28

 

21

 

33.3

%

Total other expense

 

(15,877

)

(12,949

)

22.6

%

Income before income tax expense

 

4,699

 

224

 

1,997.8

%

Income tax expense

 

196

 

155

 

26.5

%

Net income

 

$

4,503

 

$

69

 

6,426.1

%

 

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

 

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

 

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

 

Selling, general and administrative expense. Selling, general and administrative expense was $18.3 million for year ended December 31, 2012 compared to $12.7 million for the year ended December 31, 2011, an increase of 43.6%. Selling, general and administrative expense represented 15.4% and 12.9% of revenue for the years ended December 31, 2012 and 2011, respectively. Approximately $2.6 million of the increase in selling, general and administrative expense related to a rise in salaries and benefits due to (i) an increase in employee headcount to

 

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Table of Contents

 

support operations and sales management and (ii) certain executive positions to operate as a public company. Additionally, accounting fees increased $0.3 million due to increased services as we prepared to operate as a public company. Other significant increases included (1) $0.3 million due to increased office rent, (2) $0.6 million due to increased sales support costs, (3) $0.5 million of increased outside services costs and (4) $0.4 million of increased telephone and office supply expenses, all of which were attributable to increased employee headcount and support services. The selling, general and administrative employee headcount was 59 at December 31, 2012, a 15.7% increase from December 31, 2011. The selling, general and administrative employee headcount increased to support the continued growth of the business.

 

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

 

Depreciation and amortization expense. Depreciation and amortization expense was $41.9 million for the year ended December 31, 2012 compared to $32.7 million for the year ended December 31, 2011, an increase of 27.9%. The increase was related to an increase in depreciable property, plant and equipment, including the compression units purchased from Caterpillar for $43.0 million, of 33.6% over these periods.

 

Interest expense. Interest expense was $15.9 million for the year ended December 31, 2012 compared to $13.0 million for the year ended December 31, 2011, an increase of 22.6%. Included in interest expense is amortization of deferred loan costs of $1.9 million and $1.5 million for the years ended December 31, 2012 and 2011, respectively. Interest expense for both periods was related to borrowings under our revolving credit facility. Average borrowings outstanding under our revolving credit facility were $442.1 million for the year ended December 31, 2012 compared to $275.1 million for the year ended December 31, 2011. Our revolving credit facility had an interest rate of 2.96% and 3.02% at December 31, 2012 and 2011, respectively, and an average interest rate of 2.99% and 3.71%, excluding the effects from the interest rate swap instruments discussed below, for the year then ended, respectively. 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. As of December 31, 2010, we no longer designate our swap agreements as cash flow hedges. As a result, amounts paid or received from the interest rate swaps are charged or credited to interest expense. For the years ended December 31, 2012 and 2011, we recorded a fair value gain of $2.2 million and $2.6 million, respectively, with respect to these swaps as a reduction in interest expense.

 

Income tax expense. We incurred approximately $196,000 and $155,000 in franchise tax for the years ended December 31, 2012 and 2011, respectively, as a result of the Texas franchise tax.

 

Liquidity and Capital Resources

 

The following table summarizes our sources and uses of cash for the years ended December 31, 2013, 2012 and 2011, and our cash as of the end of the periods presented:

 

 

 

Year Ended December 31,

 

 

 

2013

 

2012

 

2011

 

 

 

(in thousands)

 

Net cash provided by operating activities

 

$

68,190

 

$

41,974

 

$

33,782

 

Net cash used in investing activities

 

(153,946

)

(178,589

)

(140,444

)

Net cash provided by financing activities

 

85,756

 

136,619

 

106,662

 

 

Net cash provided by operating activities. Net cash provided by operating activities increased to $68.2 million for the year ended December 31, 2013, from $42.0 million for 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 unit equipment. Net cash provided by operating activities increased to $42.0 million for the year ended December 31, 2012, from $33.8 million in the year ended December 31, 2011. The increase related primarily to a higher income level in 2012, offset by a $6.2 million decrease in working capital in the year ended December 31, 2012, primarily due to timing of payments for new compression unit equipment.

 

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Net cash used in investing activities. Net cash used in investing activities decreased to $153.9 million for the year ended December 31, 2013, from $178.6 million for the year ended December 31, 2012. The decrease related primarily to lower capital expenditures of $159.5 million during the year ended December 31, 2013, offset by (1) $0.8 million of higher proceeds from the sale of equipment during the year ended December 31, 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 used in investing activities increased to $178.6 million for the year ended December 31, 2012, from $140.4 million for the year ended December 31, 2011. The increase related primarily to higher capital expenditures of $180.0 million, offset by $0.6 million of higher proceeds from the sale of equipment during the year ended December 31, 2012.

 

Net cash provided by financing activities. Net cash provided by financing activities was $85.8 million for the year ended December 31, 2013 as compared $136.6 million for the year ended December 31, 2012. The decrease was due to lower borrowings under our revolving credit facility for the year ended December 31, 2013 due to the application of the net proceeds from our initial public offering to pay down outstanding borrowings as compared to higher borrowings for the year ended December 31, 2012 related to expansion capital expenditures.  Net cash provided by financing activities was $136.6 million for the year ended December 31, 2012 as compared to $106.7 million for the year ended December 31, 2011. The increase was due to lower borrowings under our revolving credit facility for the year ended December 31, 2011 as compared to higher borrowings for the year ended December 31, 2012 related to increased expansion capital expenditures.

 

Capital Expenditures

 

The compression business is capital intensive, requiring significant investment to maintain, expand and upgrade existing operations. Our capital requirements have consisted primarily of, and we anticipate that our capital requirements will continue to consist primarily of, the following:

 

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

 

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

 

We expect that our maintenance capital expenditure requirements will continue to increase as the overall size and age of our fleet increases. Our aggregate maintenance capital expenditures for the years ended December 31, 2013 and 2012 were $14.3 million and $13.3 million, respectively.

 

Given our growth objective, we anticipate that we will continue to make significant expansion capital expenditures. Our expansion capital expenditures for the years ended December 31, 2013 and 2012 were $323.7 million and $166.7 million, respectively. Of the $323.7 million, $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.

 

In addition to organic growth, we may also consider a variety of assets or businesses for potential acquisition. 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, including our issuance of additional partnership units and future debt offerings given market conditions.

 

Description of Revolving Credit Facility

 

We amended our revolving credit agreement in December 2010 to increase the overall commitments under the facility to $400 million and extend the term until October 5, 2015. On November 16, 2011, we amended the revolving credit agreement to increase the overall commitments under the facility from $400 million to $500 million and reduce our applicable margin for LIBOR loans from the previous range of 300 to 375 basis points above LIBOR to the new range of 200 to 275 basis points above LIBOR, depending on our leverage ratio. We further amended our revolving credit agreement on June 1, 2012 to increase the overall commitments under the facility from $500 million to $600 million and to provide an option to increase the overall commitments by an additional $50 million upon satisfaction of certain conditions.

 

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In addition, on June 1, 2012, we entered into the Fourth Amended and Restated Credit Agreement in order to provide a covenant structure that was more appropriate for a public company than was the prior credit agreement, including a reduction of the applicable margin for LIBOR loans to a range of 175 to 250 basis points above LIBOR, depending on the our leverage ratio. This amended and restated credit agreement became effective on January 18, 2013, the closing date of our initial public offering, was secured by a first priority lien against our assets and had a schedule maturity of October 5, 2015. On December 10, 2012, we amended the Fourth Amended and Restated Credit Agreement to extend the periods during which the maximum funded debt to EBITDA ratio thresholds will apply. We paid various loan fees and incurred costs in respect of the third amendment to the credit agreement and the Fourth Amended and Restated Credit Agreement in the amount of $1.8 million in 2012.

 

On December 13, 2013, we entered into the Fifth Amended and Restated Credit Agreement whereby the aggregate commitment under the facility increased from $600 million to $850 million (subject to availability under a borrowing base and a further potential increase of $100 million) and reduced the applicable margin for LIBOR loans to a range of 150 to 225 basis points above LIBOR, depending on our leverage ratio. The revolving credit facility is secured by a first priority lien against our assets and matures on December 13, 2018, at which point all amounts outstanding will become due.

 

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

 

·                  grant liens;

 

·                  make certain loans or investments;

 

·                  incur additional indebtedness or guarantee other indebtedness;

 

·                  enter into transactions with affiliates;

 

·                  merge or consolidate;

 

·                  sell our assets; or

 

·                  make certain acquisitions.

 

The Fifth Amended and Restated Credit Agreement also contains various financial covenants, including covenants requiring us to maintain:

 

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

 

·                  a maximum funded debt to EBITDA ratio, determined as of the last day of each fiscal quarter, for the annualized trailing three months of (a) 5.50 to 1.0, with respect to any fiscal quarter ending on or after December 13, 2013, the closing date of the amended credit facility, through June 30, 2015 or (b) 5.00 to 1.0, with respect to the fiscal quarter ending September 30, 2015 and each fiscal quarter thereafter, in each case subject to a provision for increases to such thresholds by 0.5 in connection with certain future acquisitions for the six consecutive month period following the period in which any such acquisition occurs.

 

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If a default exists under the revolving credit facility, the lenders will be able to accelerate the maturity on the amount then outstanding and exercise other rights and remedies.

 

As of December 31, 2013, we were in compliance with all of the covenants under our current credit agreement.

 

Distribution Reinvestment Plan

 

We have filed a registration statement with the SEC to register the issuance of up to 4,150,000 of our common units in connection with a DRIP, which initially became effective on January 30, 2013.  Our 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 18, 2014, 1,552,749 common units had been issued under this registration statement.

 

Total Contractual Cash Obligations

 

The following table summarizes our total contractual cash obligations as of December 31, 2013:

 

 

 

Payments Due by Period

 

Contractual Obligations

 

Total

 

1 year

 

2 - 3 years