Archrock, Inc. - Annual Report: 2015 (Form 10-K)
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, 2015
or
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file no. 001-33666
Archrock, Inc.
(Exact name of registrant as specified in its charter)
Delaware | 74-3204509 |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
16666 Northchase Drive, Houston, Texas 77060
(Address of principal executive offices, zip code)
(281) 836-8000
(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 Stock, $0.01 par value | New York Stock Exchange | |
Securities registered pursuant to 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No 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 ¨ 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 ¨
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 (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer x | Accelerated filer o |
Non-accelerated filer o | Smaller reporting company o |
(Do not check if a smaller reporting company) | m |
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 the common stock of the registrant held by non-affiliates as of June 30, 2015 was $1,328,362,997. For purposes of this disclosure, common stock held by persons who hold more than 5% of the outstanding voting shares and common stock held by executive officers and directors of the registrant have been excluded in that such persons may be deemed to be “affiliates” as that term is defined under the rules and regulations promulgated under the Securities Act of 1933, as amended. This determination of affiliate status is not necessarily a conclusive determination for other purposes.
Number of shares of the common stock of the registrant outstanding as of February 18, 2016: 69,630,338 shares.
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DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive proxy statement for the 2016 Meeting of Stockholders, which is expected to be filed with the Securities and Exchange Commission within 120 days after December 31, 2015, are incorporated by reference into Part III of this Form 10-K.
TABLE OF CONTENTS
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PART I
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K contains “forward-looking statements” intended to qualify for the safe harbors from liability established by the Private Securities Litigation Reform Act of 1995. All statements other than statements of historical fact contained in this Annual Report on Form 10-K are forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), including, without limitation, statements regarding our business growth strategy and projected costs; future financial position; the sufficiency of available cash flows to fund continuing operations and pay dividends; the expected amount of our capital expenditures; anticipated cost savings, future revenue, gross margin and other financial or operational measures related to our business; the future value of our equipment; and plans and objectives of our management for our future operations. You can identify many of these statements by looking for words such as “believe,” “expect,” “intend,” “project,” “anticipate,” “estimate,” “will continue” or similar words or the negative thereof.
Such forward-looking statements are subject to various risks and uncertainties that could cause actual results to differ materially from those anticipated as of the date of this Annual Report on Form 10-K. Although we believe that the expectations reflected in these forward-looking statements are based on reasonable assumptions, no assurance can be given that these expectations will prove to be correct. 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 Annual Report on Form 10-K. Important factors that could cause our actual results to differ materially from the expectations reflected in these forward-looking statements include, among other things:
• | conditions in the oil and natural gas industry, including a sustained decrease in the level of supply or demand for oil or natural gas or a sustained low price of oil or natural gas; |
• | the success of our subsidiary, Archrock Partners, L.P. (along with its subsidiaries, the “Partnership”), including the amount of cash distributions by the Partnership with respect to its general partner interests, incentive distribution rights and limited partner interests; |
• | our reduced profit margins or the loss of market share resulting from competition or the introduction of competing technologies by other companies; |
• | the completed spin-off of our international contract operations, international aftermarket services operations and global fabrication businesses into an independent, publicly traded company (“Exterran Corporation”); |
• | changes in economic or political conditions, including terrorism and legislative changes; |
• | the inherent risks associated with our operations, such as equipment defects, impairments, malfunctions and natural disasters; |
• | the loss of the Partnership’s status as a partnership for United States of America (“U.S.”) federal income tax purposes; |
• | the risk that counterparties will not perform their obligations under our financial instruments; |
• | the financial condition of our customers; |
• | our ability to timely and cost-effectively obtain components necessary to conduct our business; |
• | employment and workforce factors, including our ability to hire, train and retain key employees; |
• | our ability to implement certain business and financial objectives, such as: |
• | winning profitable new business; |
• | selling additional contract operations contracts and equipment to the Partnership; |
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• | growing our asset base and enhancing asset utilization; |
• | integrating acquired businesses; |
• | generating sufficient cash; and |
• | accessing the capital markets at an acceptable cost; |
• | liability related to the use of our services; |
• | changes in governmental safety, health, environmental or other regulations, which could require us to make significant expenditures; and |
• | our level of indebtedness and ability to fund our business. |
All forward-looking statements included in this Annual Report on Form 10-K are based on information available to us on the date of this Annual Report on Form 10-K. 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 cautionary statements contained throughout this Annual Report on Form 10-K.
Item 1. Business
General
We were incorporated in February 2007 as a wholly-owned subsidiary of Universal Compression Holdings, Inc. (“Universal”). On August 20, 2007, Universal and Hanover Compressor Company (“Hanover”) merged into our wholly-owned subsidiaries, and we became the parent entity of Universal and Hanover, named “Exterran Holdings, Inc.” In connection with the separation transaction completed on November 3, 2015 and described below, we changed our name to Archrock, Inc. References to “Archrock,” “our,” “we,” or “us” refer to Archrock, Inc. and its subsidiaries, except where the context requires otherwise. We are a pure play U.S. natural gas contract operations services business and the leading provider of natural gas compression services to customers in the oil and natural gas industry throughout the U.S. and a leading supplier of aftermarket services to customers that own compression equipment in the U.S. Our services are essential to the production, processing, transportation and storage of natural gas and are provided primarily to producers and distributors of oil and natural gas. Our geographic business unit operating structure, technically experienced personnel and large fleet of natural gas compression equipment enable us to provide reliable contract operation services to our customers throughout the U.S.
Our revenues and income are derived from two primary business segments:
• | Contract Operations. As of December 31, 2015, our contract operations business was largely comprised of our significant equity investment in Archrock Partners, L.P. and its subsidiaries, in addition to our owned fleet of natural gas compression equipment that we use to provide operations services to our customers. |
• | Aftermarket Services. Our aftermarket services business provides a full range of services to support the compression needs of customers. We sell parts and components and provide operations, maintenance, overhaul and reconfiguration services to customers who own compression equipment. |
For financial data relating to our business segments or geographic regions that accounted for 10% or more of consolidated revenue in any of the last three fiscal years, see Part II, Item 7 (“Management’s Discussion and Analysis of Financial Condition and Results of Operations”) and Note 22 (“Reportable Segments and Geographic Information”) to our Financial Statements included in Part IV, Item 15 (“Financial Statements”) of this Annual Report on Form 10-K.
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Competitive Strengths
We believe we have the following key competitive strengths:
• | Focus on outsourced compression services. We provide our customers a variety of services, including outsourced compression services and aftermarket services, in support of our customers’ production and processing operations. We believe our contract operations services generally allow our customers that outsource their compression needs to achieve higher production rates than they would achieve with their own operations, resulting in increased revenue for our customers. In addition, outsourcing allows our customers flexibility for their evolving compression needs while limiting their capital requirements. By offering services that leverage our core strengths, we believe that we can provide comprehensive solutions to meet our customers’ needs. We believe the quality of our services, the depth of our customer relationships and our presence in substantially all major oil and natural gas-producing regions position us to capture additional business. |
• | Superior customer service. We believe we operate in a relationship-driven, service-intensive industry and therefore need to provide superior customer service. We believe that our regionally-based network, local presence, experience and in-depth knowledge of our customers’ operating needs and growth plans enable us to respond to our customers’ needs and meet their evolving demands on a timely basis. In addition, we focus on achieving a high level of reliability for the services we provide in order to maximize our customers’ production levels. Our sales efforts concentrate on demonstrating our commitment to enhancing our customers’ cash flow through superior customer service and after-market support. |
• | Large fleet in substantially all major producing regions. We operate in substantially all major oil and natural gas producing regions in the U.S. Our large fleet and numerous operating locations throughout the U.S., combined with our ability to efficiently move equipment among producing regions, means that we are not dependent on production activity in any particular region. We believe our size, geographic scope and broad customer base provide us with improved operating expertise and business development opportunities. |
• | Our relationship with the Partnership. As of December 31, 2015, we held a 39% ownership interest in the Partnership’s limited partner units as well as all of the general partner interests and incentive distribution rights in the Partnership. We expect that the Partnership will be the primary vehicle through which we grow our contract operations business and our ownership interest in the Partnership will allow us to participate in its future growth. In addition, we believe that our relationship with the Partnership will continue to provide us with cash flows to support our business. |
• | Fee-based cash flows. We charge a fixed monthly fee for our contract operations services that our customers are generally required to pay, regardless of the volume of natural gas we compress in that month. We believe this fee structure reduces volatility and enhances our ability to generate relatively stable and predictable cash flows. |
Business Strategies
We intend to continue to capitalize on our competitive strengths to meet our customers’ needs through the following key strategies:
• | Capitalize on the long-term fundamentals for the U.S. natural gas compression industry. We believe our ability to efficiently meet our customers’ evolving compression needs, our long-standing customer relationships and our large compressor fleet will enable us to capitalize on what we believe are favorable long-term fundamentals for the U.S. natural gas compression industry. These fundamentals include significant natural gas resources in the U.S., increased unconventional natural gas production, decreasing natural reservoir pressures, expected increased natural gas demand in the U.S. from growth in liquid natural gas exports, exports of natural gas via pipeline to Mexico, power generation and industrial uses, and the continued need for compression services. |
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• | Grow our business to generate attractive returns. We plan to continue to invest in strategically growing our business both organically and through third-party acquisitions. Our contract operations business is our largest business segment based on gross margin, representing approximately 92% of our gross margin during 2015. We see opportunities to grow this business over the long term by putting idle units back to work and adding new horsepower in key growth areas, including providing compression services to producers of natural gas from shale and liquids-rich plays. In addition, because a large amount of compression equipment is owned by oil and gas producers, processors, gatherers, transporters and storage providers, we believe there will be additional opportunities for our aftermarket services business, which represented approximately 8% of our gross margin during 2015, to provide parts and services to support the operation of this equipment. |
• | Leverage our relationship with the Partnership. As of December 31, 2015, we held a 39% ownership interest in the Partnership’s limited partner units as well as all of the general partner interest and incentive distribution rights in the Partnership. We intend to utilize the Partnership as our primary vehicle for the long-term growth of our contract operations business. We expect to grow the Partnership through third-party acquisitions, organic growth opportunities and the future transfer by us of additional contract operations customer contracts and equipment to the Partnership in exchange for cash, the Partnership’s assumption of a portion of our debt and/or additional equity interests in the Partnership. |
• | Lower costs and improve profitability. As the largest provider of natural gas compression services in the U.S., we intend to use our scale to achieve cost savings in our operations. We are also focused on increasing productivity and optimizing our processes. By making our systems and processes more efficient, we intend to lower our internal costs and improve our profitability over time. |
Contract Operations Services Overview
We provide comprehensive contract operations services, including the personnel, equipment, tools, materials and supplies to meet our customers’ natural gas compression needs. Based on the operating specifications at the customer’s location and the customer’s unique needs, these services include designing, sourcing, owning, installing, operating, servicing, repairing and maintaining equipment to provide these services to our customers. When providing contract compression services, we work closely with a customer’s field service personnel so that the compression services can be adjusted to efficiently match changing characteristics of the natural gas reservoir and the natural gas produced. We routinely repackage or reconfigure a portion of our existing fleet to adapt to our customers’ compression services needs. We utilize both slow and high speed reciprocating compressors primarily driven by internal natural gas fired combustion engines. We also utilize rotary screw compressors for specialized applications.
Our equipment is maintained in accordance with established maintenance schedules. These maintenance procedures are updated as technology changes and as our operations group develops new techniques and procedures. In addition, because our field technicians provide maintenance on our contract operations equipment, they are familiar with the condition of our equipment and can readily identify potential problems. In our experience, these maintenance procedures maximize equipment life and unit availability, minimize avoidable downtime and lower the overall maintenance expenditures over the equipment life. Generally, each of our compressor units undergoes a major overhaul once every three to seven years, depending on the type, size and utilization of the unit.
We believe that our aftermarket services, described below, provide opportunities to cross-sell our contract operations services. Our customers typically contract for our services on a site-by-site basis for a specific monthly service rate that is generally reduced if we fail to operate in accordance with the contract requirements. Following the initial minimum term, which is typically around twelve months, contract operations services generally continue until terminated by either party with 30 days’ advance notice. Our customers generally are required to pay our monthly service fee even during periods of limited or disrupted natural gas flows. Additionally, because we typically do not take title to the natural gas we compress and because the natural gas we use as fuel for our compressors and other equipment is supplied by our customers, we have limited direct exposure to commodity price fluctuations.
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We maintain field service locations from which we can service and overhaul our own compressor fleet to provide contract operations services to our customers. We also use many of these locations to provide aftermarket services to our customers, as described in more detail below. As of December 31, 2015, our contract operations segment provided contract operations services primarily using a fleet of 7,960 natural gas compression units with an aggregate capacity of approximately 4.0 million horsepower. During the year ended December 31, 2015, 78% of our total revenue and 92% of our total gross margin was generated from contract operations. Gross margin, a non-GAAP financial measure, is reconciled, in total, to net income (loss), its most directly comparable financial measure calculated and presented in accordance with GAAP in Part II, Item 6 (“Selected Financial Data — Non-GAAP Financial Measures”) of this Annual Report on Form 10-K.
Archrock Partners, L.P.
We have a significant equity interest in the Partnership, a master limited partnership that provides natural gas contract operations services to customers throughout the U.S. As of December 31, 2015, public unitholders held a 59% ownership interest in the Partnership and we owned the remaining equity interest, including all of the general partner interest and incentive distribution rights. We consolidate the financial position and results of operations of the Partnership. It is our intention for the Partnership to be the primary vehicle for the growth of our contract operations business, and we may grow the Partnership through third-party acquisitions, organic growth and the future transfer by us of additional contract operations customer contracts and equipment to the Partnership in exchange for cash, the Partnership’s assumption of our debt and/or additional equity interests in the Partnership. As of December 31, 2015, the Partnership’s fleet included 6,494 compressor units comprising approximately 3.3 million horsepower, or 83% of our and the Partnership’s combined total U.S. horsepower.
On April 17, 2015, we sold to the Partnership contract operations customer service agreements with 60 customers and a fleet of 238 compressor units used to provide compression services under those agreements, comprising approximately 148,000 horsepower, or 3% (of then available horsepower) of the combined contract operations business of the Partnership and us. The assets sold to the Partnership also included 179 compressor units, comprising approximately 66,000 horsepower, previously leased by us to the Partnership. Total consideration for the transaction was approximately $102.3 million, excluding transaction costs, and consisted of the Partnership’s issuance to us of approximately 4.0 million common units and approximately 80,000 general partner units. Based on the terms of the contribution, conveyance and assumption agreement relating to the acquisition, the common units and general partner units, including incentive distribution rights, we received in this transaction were not entitled to receive a cash distribution relating to the quarter ended March 31, 2015. We refer to this acquisition as the “April 2015 Contract Operations Acquisition.”
On August 8, 2014, the Partnership completed an acquisition of natural gas compression assets, including a fleet of 162 compressor units, comprising approximately 110,000 horsepower from MidCon Compression, L.L.C. (“MidCon”) for $130.1 million. The majority of the horsepower acquired is utilized under a five-year contract operations services agreement with BHP Billiton Petroleum (“BHP Billiton”), which expires in March 2019, to provide compression services. In accordance with the terms of the purchase and sale agreement relating to this acquisition, the Partnership directed MidCon to sell a tract of real property and the facility located thereon, a fleet of vehicles, personal property and parts inventory to one of our wholly-owned subsidiaries, for $4.1 million. These assets are used in conjunction with the compression units the Partnership acquired from MidCon to provide compression services. We refer to the acquisition of these assets by the Partnership and our wholly-owned subsidiary as the “August 2014 MidCon Acquisition.”
On April 10, 2014, the Partnership completed an acquisition of natural gas compression assets, including a fleet of 337 compressor units, comprising approximately 444,000 horsepower from MidCon for $352.9 million. The compressor units were previously used by MidCon to provide compression services to a subsidiary of Access Midstream Partners, L.P. (“Access”). Effective as of the closing of the acquisition, the Partnership and Access entered into a seven-year contract operations services agreement under which the Partnership provides compression services to Access which, following its February 2015 merger with Williams Partners L.P., was renamed Williams Partners L.P. (“Williams Partners”). In accordance with the terms of the purchase and sale agreement relating to this acquisition, the Partnership directed MidCon to sell a tract of real property and the facility located thereon, a fleet of vehicles, personal property and parts inventory to one of our wholly-owned subsidiaries for $7.7 million. These assets are used in conjunction with the compression units the Partnership acquired from MidCon to provide compression services. We refer to the acquisition of these assets by the Partnership and our wholly-owned subsidiary as the “April 2014 MidCon Acquisition.”
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Compressor Fleet
The size and horsepower of our natural gas compressor fleet on December 31, 2015 is summarized in the following table:
Range of Horsepower Per Unit | Number of Units | Aggregate Horsepower (in thousands) | % of Horsepower | |||||
0 – 200 | 3,225 | 369 | 9 | % | ||||
201 – 500 | 2,325 | 629 | 16 | % | ||||
501 – 800 | 533 | 334 | 8 | % | ||||
801 – 1,100 | 292 | 279 | 7 | % | ||||
1,101 – 1,500 | 1,184 | 1,613 | 40 | % | ||||
1,501 and over | 401 | 787 | 20 | % | ||||
Total | 7,960 | 4,011 | 100 | % | ||||
As of December 31, 2015, the Partnership’s fleet included 6,494 of these compressor units comprising approximately 3.3 million horsepower, or 83% of our and the Partnership’s combined total horsepower. As of December 31, 2015, the Partnership’s fleet included 50 compressor units, comprising approximately 17,000 horsepower, leased from our wholly-owned subsidiaries and excluded 31 compressor units, comprising approximately 12,000 horsepower, owned by the Partnership but leased to our wholly-owned subsidiaries.
Over the last several years, we have undertaken efforts to standardize our compressor fleet around major components and key suppliers. The standardization of our fleet:
• | enables us to minimize our fleet operating costs and maintenance capital requirements; |
• | enables us to reduce inventory costs; |
• | facilitates low-cost compressor resizing; and |
• | allows us to develop improved technical proficiency in our maintenance and overhaul operations, which enables us to achieve high run-time rates while maintaining lower operating costs. |
Aftermarket Services Overview
Our aftermarket services segment sells parts and components and provides operation, maintenance, overhaul and reconfiguration services to customers who own compression and oilfield power generation equipment. We believe that we are particularly well qualified to provide these services because our highly experienced operating personnel have access to the full range of our compression services and facilities. During the year ended December 31, 2015, 22% of our total revenue and 8% of our total gross margin was generated from aftermarket services.
Spin-off Transaction
On November 3, 2015 (the “Distribution Date”), we completed the spin-off (the “Spin-off”) of our international contract operations, international aftermarket services and global fabrication businesses into a standalone public company operating as Exterran Corporation. To effect the Spin-off, we distributed on the Distribution Date, on a pro rata basis, all of the shares of Exterran Corporation common stock to our stockholders as of October 27, 2015 (the “Record Date”). Archrock stockholders received one share of Exterran Corporation common stock for every two shares of our common stock held at the close of business on the Record Date. Upon the completion of the Spin-off, we were renamed “Archrock, Inc.” and, on November 4, 2015, the ticker symbol for our common stock on the New York Stock Exchange was changed to “AROC.” Following the completion of the Spin-off, we and Exterran Corporation are independent, publicly traded companies with separate public ownership, board of directors and management, and we continue to own and operate the U.S. contract operations and aftermarket services businesses that we previously owned. Additionally, we continue to hold our interests in the Partnership. Effective on November 3, 2015, the Partnership was renamed “Archrock Partners, L.P.,” and, on November 4, 2015, the ticker symbol for its common units on the Nasdaq Global Select Market was changed to “APLP.”
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In order to effect the Spin-off and govern our relationship with Exterran Corporation after the Spin-off, we entered into several agreements with Exterran Corporation on November 3, 2015:
• | Separation and Distribution Agreement. Our separation and distribution agreement with Exterran Corporation contains the key provisions relating to the separation of our business from Exterran Corporation’s business. The separation and distribution agreement identifies the assets and rights that were transferred, liabilities that were assumed or retained and contracts and related matters that were assigned to us or Exterran Corporation in the Spin-off and describes how these transfers, assumptions and assignments occurred. In addition, the separation and distribution agreement contains certain noncompetition provisions addressing restrictions for three years after the Spin-off on Exterran Corporation’s ability to provide contract operations and aftermarket services in the United States and on our ability to provide contract operations and aftermarket services outside of the United States and to provide products for sale worldwide that compete with Exterran Corporation’s product sales business, subject to certain exceptions. |
• | Tax Matters Agreement. Our tax matters agreement with Exterran Corporation governs the respective rights, responsibilities and obligations of Exterran Corporation and us with respect to tax liabilities and benefits, tax attributes, the preparation and filing of tax returns, the control of audits and other tax proceedings and certain other matters regarding taxes. |
• | Employee Matters Agreement. Our employee matters agreement with Exterran Corporation governs the allocation of liabilities and responsibilities between us and Exterran Corporation relating to employee compensation and benefit plans and programs, including the treatment of retirement, health and welfare plans and equity and other incentive plans and awards. |
• | Transition Services Agreement. Our transition services agreement with Exterran Corporation sets forth the terms on which Exterran Corporation will provide to us, and we will provide to Exterran Corporation, on a temporary basis, certain services or functions that the companies historically have shared, including accounting, administrative, payroll, human resources, environmental health and safety, real estate, fleet, financial audit support, legal, tax, treasury and other support and corporate services. |
• | Supply Agreement. Our supply agreement with Exterran Corporation sets forth the terms under which Exterran Corporation will provide manufactured equipment, including the design, engineering, manufacturing and sale of natural gas compression equipment, on an exclusive basis to us and the Partnership. |
Exterran Corporation’s capital structure includes a new $925.0 million credit facility, consisting of a $680.0 million revolving credit facility and a $245.0 million term loan facility (collectively, the “Exterran Corporation Credit Facility”) that became available on November 3, 2015. Exterran Corporation transferred the net proceeds from the borrowings under the Exterran Corporation Credit Facility to us to allow for our repayment of a portion of our indebtedness prior to the Spin-off. Our capital structure includes a new $350.0 million revolving credit facility that became available on November 3, 2015.
Results of operations for Exterran Corporation have been classified as discontinued operations in all periods presented in this Annual Report on Form 10-K. For additional information, see Note 2 (“Discontinued Operations”) to our Financial Statements within Part IV, Item 15 “Exhibits and Financial Statement Schedules” in this Annual Report on Form 10-K.
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Natural Gas Compression Industry Overview
Natural gas compression is a mechanical process whereby the pressure of a given volume of natural gas is increased to a desired higher pressure for transportation from one point to another. It is essential to the production and transportation of natural gas. Compression is typically required several times during the natural gas production and transportation cycle, including (i) at the wellhead, (ii) throughout gathering and distribution systems, (iii) into and out of processing and storage facilities and (iv) along intrastate and interstate pipelines.
• | Wellhead and Gathering Systems — Natural gas compression is used to transport natural gas from the wellhead through the gathering system. At some point during the life of natural gas wells reservoir, pressures typically fall below the line pressure of the natural gas gathering or pipeline system used to transport the natural gas to market. At that point, natural gas no longer naturally flows into the pipeline. Compression equipment is applied in both field and gathering systems to boost the pressure levels of the natural gas flowing from the well allowing it to be transported to market. Changes in pressure levels in natural gas fields require periodic changes to the size and/or type of on-site compression equipment. Additionally, compression is used to reinject natural gas into producing oil wells to maintain reservoir pressure and help lift liquids to the surface, which is known as secondary oil recovery or natural gas lift operations. Typically, these applications require low- to mid-range horsepower compression equipment located at or near the wellhead. Compression equipment is also used to increase the efficiency of a low-capacity natural gas field by providing a central compression point from which the natural gas can be produced and injected into a pipeline for transmission to facilities for further processing. |
• | Pipeline Transportation Systems — Natural gas compression is used during the transportation of natural gas from the gathering systems to storage or the end user. Natural gas transported through a pipeline loses pressure over the length of the pipeline. Compression is staged along the pipeline to increase capacity and boost pressure to overcome the friction and hydrostatic losses inherent in normal operations. These pipeline applications generally require larger horsepower compression equipment (1,500 horsepower and higher). |
• | Storage Facilities — Natural gas compression is used in natural gas storage projects for injection and withdrawals during the normal operational cycles of these facilities. |
• | Processing Applications — Compressors may also be used in combination with natural gas production and processing equipment and to process natural gas into other marketable energy sources. In addition, compression services are used for compression applications in refineries and petrochemical plants. |
Many natural gas producers, transporters and processors outsource their compression services due to the benefits and flexibility of contract compression. Changing well and pipeline pressures and conditions over the life of a well often require producers to reconfigure or replace their compressor units to optimize the well production or gathering system efficiency.
We believe outsourcing compression operations to compression service providers such as us offers customers:
• | the ability to efficiently meet their changing compression needs over time while limiting the underutilization of their owned compression equipment; |
• | access to the compression service provider’s specialized personnel and technical skills, including engineers and field service and maintenance employees, which we believe generally leads to improved production rates and/or increased throughput; |
• | the ability to increase their profitability by transporting or producing a higher volume of natural gas through decreased compression downtime and reduced operating, maintenance and equipment costs by allowing the compression service provider to efficiently manage their compression needs; and |
• | the flexibility to deploy their capital on projects more directly related to their primary business by reducing their compression equipment and maintenance capital requirements. |
We believe the U.S. natural gas compression services industry continues to have growth potential over time due to, among other things, increased natural gas production in the U.S. from unconventional sources and aging producing natural gas fields that will require more compression to continue producing the same volume of natural gas, and expected increased demand for natural gas in the U.S. for power generation, industrial uses and exports, including liquefied natural gas exports and exports of natural gas via pipeline to Mexico.
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Trends and Outlook
Our business environment and corresponding operating results are affected by the level of energy industry spending for the exploration, development and production of oil and natural gas reserves in the U.S. Spending by oil and natural gas exploration and production companies is dependent upon these companies’ forecasts regarding the expected future supply, demand and pricing of oil and natural gas products as well as their estimates of risk-adjusted costs to find, develop and produce reserves. Oil and natural gas prices and the level of drilling and exploration activity can be volatile. For example, oil and natural gas exploration and development activity and the number of well completions typically decline when there is a significant reduction in oil and natural gas prices or significant instability in energy markets. Our revenue, earnings and financial position are affected by, among other things, market conditions that impact demand and pricing for natural gas compression, our customers’ decisions between using our services or our competitors’ services, our customers’ decisions regarding whether to own and operate the equipment themselves and the timing and consummation of any acquisition of additional contract operations customer service agreements and equipment from third parties. Although we believe our business is typically less impacted by commodity prices than certain other oil and natural gas service providers, changes in oil and natural gas exploration and production spending normally result in changes in demand for our services.
Natural gas consumption in the U.S. for the twelve months ended November 30, 2015 increased by approximately 2% to approximately 27,551 billion cubic feet (“Bcf”) compared to approximately 26,931 Bcf for the twelve months ended November 30, 2014. The U.S. Energy Information Administration (“EIA”) forecasts that total U.S. natural gas consumption will increase by 1.5% in 2016 compared to 2015. The EIA estimates that the U.S. natural gas consumption level will be approximately 30 trillion cubic feet (“Tcf”) in 2040, or 16% of the projected worldwide total of approximately 185 Tcf.
Natural gas marketed production in the U.S. for the twelve months ended November 30, 2015 increased by approximately 6% to 28,849 Bcf compared to 27,096 Bcf for the twelve months ended November 30, 2014. The EIA forecasts that total U.S. natural gas marketed production will increase by 0.7% in 2016 compared to 2015. The EIA estimates that the U.S. natural gas production level will be approximately 33 Tcf in 2040, or 18% of the projected worldwide total of approximately 187 Tcf.
Historically, oil and natural gas prices in the U.S. have been volatile. For example, the Henry Hub spot price for natural gas was $2.28 per MMBtu at December 31, 2015, which was approximately 8% and 27% lower than prices at September 30, 2015 and December 31, 2014, respectively, and the U.S. natural gas liquid composite price was $4.72 per MMBtu for the month of November 2015, which was approximately 3% and 16% lower than the price for the months of September 2015 and December 2014, respectively. These price declines have caused many companies to reduce their natural gas drilling and production activities, particularly in more mature and predominantly dry gas areas and shale plays in the U.S., where we provide a significant amount of contract operations services, which led to a decline in our contract operations business during 2015. These price declines are expected to lead to a continued decrease in capital investment and in the number of new gas wells being drilled in 2016 by exploration and production companies. In addition, the West Texas Intermediate crude oil spot price was $37.13 per barrel at December 31, 2015 which was approximately 18% and 31% lower than prices at September 30, 2015 and December 31, 2014, respectively, which is expected to lead to a continued decrease in capital investment and in the number of new oil wells being drilled in 2016 by exploration and production companies. Because we provide a significant amount of contract operations services related to the production of associated gas from oil wells and the use of gas lift to enhance production of oil from oil wells, our operations and our levels of operating horsepower are also impacted by crude oil drilling and production activity.
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During periods of lower oil or natural gas prices, our customers may not be able to recover the full amount of their drilling and production costs in the regions in which we operate. As a result, our customers may cease production in existing wells and decline to drill new wells, which would lower their demand for our services. Additionally, some of our midstream customers may provide their gathering, transportation and related services to a limited number of companies in the oil and gas production business. The loss by these midstream customers of their key customers could reduce demand for their services and result in a deterioration of their financial condition, which would in turn decrease their demand for our services. A reduction in the demand for our services could result in our customers seeking to preserve capital by canceling contracts, canceling or delaying scheduled maintenance of their existing equipment or determining not to enter into new contract operations service contracts, which could force us to reduce our pricing substantially. As a result of the significant decline in oil and natural gas prices since the third quarter of 2014, U.S. producers reduced their capital budgets for 2015 and research analysts are forecasting declines in U.S. capital spending for drilling activity in 2016. In 2015, we experienced an operating horsepower decline. Due to the expected continued decline in customer spending in 2016 and the expectation that customers will cease production from uneconomic wells, we anticipate lower demand for our services during 2016 than in 2015. As a result, we expect continued operating horsepower declines in 2016 and we may also experience increased pricing pressure on the services we provide during 2016, which is expected to result in a decline in our contract operations business in 2016. We also anticipate investing less capital in new fleet units in 2016 than we did in 2015.
At the time of the Spin-off we had recorded $144.3 million in foreign tax credit deferred tax assets. These deferred tax assets related to foreign tax credits that can be used to reduce our income taxes payable in the current and future years. They will expire if they are not used within the 10-year carryforward period. As a result of the Spin-off it is projected that these Foreign tax credits/deductions allocated to Exterran Corporation will expire unused because Exterran Corporation will not generate sufficient taxable income and foreign source taxable income after the Spin-off to utilize these credits. Therefore in the fourth quarter we wrote off foreign tax credits for the years 2005-2010 in the amount of $48.2 million and set up a valuation allowance for the years 2011-2015 of $37.8 million for a total impact to Archrock’s fourth quarter tax provision of $86.0 million. The credits and offsetting valuation allowance were allocated to Exterran Corporation for their use in future tax returns.
We may contribute additional contract operations customer contracts and equipment to the Partnership in the future in exchange for cash, the Partnership’s assumption of our debt and/or our receipt of additional interests in the Partnership. Any such transaction depends on, among other things, market and economic conditions, our ability to agree with the Partnership regarding the terms of any purchase and the availability to the Partnership of debt and equity capital on reasonable terms.
Oil and Natural Gas Industry Cyclicality and Volatility
Changes in oil and natural gas exploration and production spending normally results in changes in demand for our products and services; however, we believe our contract operations business is typically less impacted by commodity prices than certain other energy products and service providers because:
• | compression services are necessary for natural gas to be delivered from the wellhead to end users; |
• | the need for compression services and equipment has grown over time due to the increased production of natural gas, the natural pressure decline of natural gas producing basins and the increased percentage of natural gas production from unconventional sources; and |
• | our contract operations business is tied primarily to natural gas and oil production and consumption, which are generally less cyclical in nature than exploration activities. |
Because we typically do not take title to the natural gas we compress, and because the natural gas we use as fuel for our compressors is supplied by our customers, our direct exposure to commodity price risk is further reduced.
Seasonal Fluctuations
Our results of operations have not historically reflected any material seasonal tendencies and we currently do not believe that seasonal fluctuations will have a material impact on us in the foreseeable future.
Market and Customers
Our customer base consists primarily of companies engaged in all aspects of the oil and natural gas industry, including large integrated oil and natural gas producers, processors, gatherers, transporters and storage providers.
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We conduct our contract operations activities throughout the U.S. We currently operate in substantially all major oil and natural gas producing areas throughout the entire U.S.
We have entered into preferred vendor arrangements with some of our customers that give us preferential consideration for the compression needs of these customers. In exchange, we provide these customers with enhanced product availability, product support and favorable pricing.
During the year ended December 31, 2015, Williams Partners (formerly known as Access) accounted for approximately 12% of our consolidated revenue. During the year ended December 31, 2014, Access accounted for approximately 3% of our consolidated revenue. Access merged with Williams Partners, a publicly traded limited partnership controlled by The Williams Companies, Inc. (“Williams Parent”), in February 2015 and, on an as-combined basis, Access and Williams Partners would have accounted for approximately 10% of our consolidated revenue during the year ended December 31, 2014. No other customer accounted for more than 10% of our consolidated revenue during the years ended December 31, 2015 and 2014 and no single customer accounted for more than 10% of our consolidated revenue during the year ended December 31, 2013.
On September 28, 2015, Williams Parent and Energy Transfer Equity, L.P. (“ETE”) announced that they had entered into a definitive merger agreement pursuant to which an affiliate of ETE will acquire Williams Parent, and, as a result, ETE will control Williams Parent and, indirectly, Williams Partners (the “Williams Merger”). There is no guarantee that, upon the expiration of the Partnership’s existing services agreements with Williams Partners, Williams Partners will choose (or, if the Williams Merger closes, ETE will cause Williams Partners) to renew these existing services agreements or enter into similar agreements with the Partnership. The loss of our business with Williams Partners, unless offset by additional contract compression services revenue from other customers, or the inability or failure of Williams Partners to meet its payment obligations under our contractual arrangements, could have a material adverse effect on our business, results of operations, financial condition and ability to pay cash dividends.
Sales and Marketing
Our marketing and client service functions are coordinated and performed by our sales and field service personnel. Salespeople and field service personnel regularly visit our customers to ensure customer satisfaction, to determine customer needs in respect of services currently being provided and to ascertain potential future compression services requirements. This ongoing communication allows us to quickly identify and respond to customer requests.
General Terms of our Contract Operations Customer Service Agreements
The following discussion describes select material terms common to our standard contract operations service agreements. We typically enter into a master service agreement with each customer that sets forth the general terms and conditions of our services, and then enter into a separate supplemental service agreement for each distinct site at which we will provide contract operations services.
Term and Termination. Our customers typically contract for our contract operations services on a site-by-site basis. Following the initial minimum term for our contract operations services, which is typically around twelve months, contract operations services generally continue until terminated by either party with 30 days’ advance notice.
Fees and Expenses. Our customers pay a fixed monthly fee for our contract operations services, which generally is based on expected natural gas volumes and pressures associated with a specific application. Our customers generally are required to pay our monthly fee even during periods of limited or disrupted natural gas flows. We are typically responsible for the costs and expenses associated with our compression equipment used to provide the contract operations services, other than fuel gas, which is provided by our customers.
Service Standards and Specifications. We provide contract operations services according to the particular specifications of each job, as set forth in the applicable contract. These are typically turn-key service contracts under which we supply all service and support and use our own compression equipment to provide the contract operations services as necessary for a particular application. In certain circumstances, if the availability of our services does not meet certain percentages specified in our contracts, our customers are generally entitled, upon request, to specified credits against our service fees.
Title; Risk of Loss. We own and retain title to or have an exclusive possessory interest in all compression equipment used to provide the contract operations services and we generally bear risk of loss for such equipment to the extent not caused by gas conditions, our customers’ acts or omissions or the failure or collapse of the customer’s over-water job site upon which we provide the contract operations services.
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Insurance. Typically, both we and our customers are required to carry general liability, worker’s compensation, employers’ liability, automobile and excess liability insurance. We insure our property and operations and are substantially self-insured for worker’s compensation, employer’s liability, property, auto liability, general liability and employee group health claims in view of the relatively high per-incident deductibles we absorb under our insurance arrangements for these risks.
Suppliers
Prior to the Spin-off, we fabricated compression and production and processing equipment to provide contract operations services and to sell to third parties from components and subassemblies, most of which we acquired from a wide range of vendors. On November 3, 2015, in connection with our contribution of our global fabrication business to Exterran Corporation in the Spin-off, we entered into a supply agreement with Exterran Corporation under which, during the term of the agreement, we are required to purchase our requirements of newly-fabricated compression equipment from Exterran Corporation and its affiliates, subject to certain exceptions. Pursuant to the supply agreement, if we acquire a new business that is not party to a firm supply agreement, then we will use our commercially reasonable efforts to order such business’s newly fabricated compressor requirements from Exterran Corporation. If, however, the new business is already party to a firm supply agreement, then we may continue to order such equipment under that existing third-party supply agreement as long as orders for the succeeding twelve-month period do not exceed such business’s orders for the prior twelve-month period. As a result of our entry into the supply agreement, we will rely on Exterran Corporation, who in turn relies on a limited number of suppliers, for some of the components used in its products. We believe alternative sources of these components are generally available but at prices that may not be as economically advantageous to Exterran Corporation as those offered by our existing suppliers. We believe Exterran Corporation’s relations with its suppliers are satisfactory.
Competition
The natural gas compression services business is highly competitive. Overall, we experience considerable competition from 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. We believe we are competitive with respect to price, equipment availability, customer service, flexibility in meeting customer needs, technical expertise, quality and reliability of our compressors and related services.
Increased size and geographic scope offer compression services providers operating and cost advantages. As the number of compression applications and size of the compression fleet increases, the number of required sales, administrative and maintenance personnel increases at a lesser rate, resulting in operational efficiencies and potential cost advantages. Additionally, broad geographic scope allows compression service providers to more efficiently provide services to all customers, particularly those with compression applications in remote locations. We believe our large, diverse fleet of compression equipment and broad geographic base of operations and related operational personnel give us more flexibility in meeting our customers’ needs than many of our competitors.
Environmental and Other Regulations
Government Regulation
Our operations are subject to stringent and complex U.S. federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment and to occupational safety and health. 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. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of investigatory and remedial obligations, and the issuance of injunctions delaying or prohibiting operations. We believe that our operations are in substantial compliance with applicable environmental and safety and health laws and regulations and that continued compliance with currently applicable requirements would not have a material adverse effect on us. However, the clear trend in environmental regulation is to place more restrictions on activities that may affect the environment, and thus, any changes in these laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal, emission or remediation requirements could have a material adverse effect on our results of operations and financial position.
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The primary U.S. federal environmental laws to which our operations are subject include the Clean Air Act (“CAA”) and regulations thereunder, which regulate air emissions; the Clean Water Act (“CWA”) and regulations thereunder, which regulate the discharge of pollutants in industrial wastewater and storm water runoff; the Resource Conservation and Recovery Act (“RCRA”) and regulations thereunder, which regulate the management and disposal of hazardous and non-hazardous solid wastes; and the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and regulations thereunder, known more commonly as “Superfund,” which imposes liability for the remediation of releases of hazardous substances in the environment. We are also subject to regulation under the U.S. federal Occupational Safety and Health Act (“OSHA”) and regulations thereunder, which regulate the protection of the safety and health of workers. Analogous state and local laws and regulations may also apply.
Air Emissions
The CAA and analogous state laws and their implementing regulations regulate emissions of air pollutants from various sources, including natural gas compressors, and also impose various monitoring and reporting requirements. Such laws and regulations may require a facility to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions. Our standard contract operations agreement typically provides that the customer will assume permitting responsibilities and certain environmental risks related to site operations.
New Source Performance Standards (“NSPS”)
On September 18, 2015, the U.S. Environmental Protection Agency (“EPA”) issued proposed regulations that would amend the NSPS for the oil and natural gas source category and would apply to sources of emissions of methane and volatile organic compounds (“VOC”) from certain processes, activities and equipment that is constructed, modified or reconstructed after that date. Specifically, the proposed regulation contains both methane and VOC standards for several emission sources not currently covered by the NSPS, such as fugitive emissions from compressor stations and pneumatic pumps and methane standards for certain emission sources that are already regulated for VOC, such as equipment leaks at natural gas processing plants. The proposed amendments also establish methane standards for a subset of equipment that the current NSPS regulates, including reciprocating compressors and pneumatic controllers, and extend the current VOC standards to the remaining unregulated equipment. At this point, we cannot predict whether any such proposed regulations would require us to incur material costs.
Venting and Flaring on Federal Lands
On January 22, 2016, the U.S. Department of the Interior’s Bureau of Land Management proposed a new regulation to reduce venting and flaring on federal lands. If adopted as proposed, the regulation would require leak detection inspections at compressor stations and would impose requirements to reduce emissions from pneumatic controllers, among other things. At this point, we cannot predict whether the proposed regulation would require us to incur material costs.
National Ambient Air Quality Standards (“NAAQS”)
On October 1, 2015, the EPA issued a new NAAQS ozone standard of 70 parts per billion (ppb), which is a reduction from the 75 ppb standard set in 2008. This new standard became effective on December 28, 2015. The states are expected to establish revised attainment/non-attainment regions based on the revised ozone standard by approximately October 2017, utilizing air quality data collected between 2014 and 2016. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our customers’ ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant.
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TCEQ
In addition, in January 2011, the Texas Commission on Environmental Quality (“TCEQ”) finalized revisions to certain air permit programs that significantly increase air emissions-related requirements for new and certain existing oil and gas production and gathering sites in the Barnett Shale production area. The final rule established 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, and the lower emissions standards will become applicable between 2020 and 2030 depending on the type of engine and the permitting requirements. A number of other states where our engines are operated have adopted or are considering adopting additional regulations that could impose new air permitting or pollution control requirements for engines, some of which could entail material costs to comply. At this point, however, we cannot predict whether any such rules would require us to incur material costs.
Generally
These new regulations and proposals, when finalized, and any other new regulations requiring the installation of more sophisticated pollution control equipment or the adoption of other environmental protection measures, could have a material adverse impact on our business, financial condition, results of operations and cash flows.
Climate change legislation and regulatory initiatives could result in increased compliance costs.
The U.S. Congress has previously considered legislation to restrict or regulate emissions of greenhouse gases, such as carbon dioxide and methane. One bill, passed by the House of Representatives in 2009, but never adopted by the full Congress, would have required greenhouse gas emissions reductions by covered sources of as much as 17% from 2005 levels by 2020 and by as much as 83% by 2050. 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 continue to be proposed that may be relevant to greenhouse gas emissions issues. In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address greenhouse gas emissions, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs. Although most of the state-level initiatives have to date been focused on large sources of greenhouse gas emissions, such as electric power plants, it is possible that smaller sources such as our gas-fired compressors could become subject to greenhouse gas-related regulation. Depending on the particular program, we could be required to control emissions or to purchase and surrender allowances for greenhouse gas emissions resulting from our operations.
Independent of Congress, the EPA has been pursuing regulations controlling greenhouse gas emissions under its existing CAA authority. The EPA has adopted rules requiring many facilities, including petroleum and natural gas systems, to inventory and report their greenhouse gas emissions. These reporting obligations were triggered for some sites we operated in 2015.
In addition, the EPA in June 2010 published a final rule providing for the tailored applicability of air permitting requirements for greenhouse gas emissions. The EPA reported that the rulemaking was necessary because without it certain permitting requirements would apply as of January 2011 at an emissions level that would have greatly increased the number of required permits and, among other things, imposed undue costs on small sources and overwhelmed the resources of permitting authorities. In the rule, the EPA established two initial steps of phase-in to minimize those burdens, excluding certain smaller sources from greenhouse gas permitting until at least April 30, 2016. On January 2, 2011, the first step of the phase-in applied only to new projects at major sources (as defined under those CAA permitting programs) that, among other things, increase net greenhouse gas emissions by 75,000 tons per year. On July 1, 2011, the second step of the phase-in began requiring permitting for otherwise minor sources of air emissions that have the potential to emit at least 100,000 tons per year of greenhouse gases. On June 29, 2012, the EPA issued final regulations for “Phase III” of its program, retaining the permitting thresholds established in Phases I and II. On June 23, 2014, the U.S. Supreme Court held that greenhouse gas emissions alone cannot trigger an obligation to obtain such an air permit even if the project will substantially increase the source’s greenhouse gas emissions. However, for those sources that trigger such air permitting requirements based on their traditional criteria pollutant emissions, the permit must include a limit for greenhouse gases. In addition, the Court concluded that the rule was flawed because the EPA failed to identify a de minimis threshold for greenhouse gases below which Best Available Control Technology would not be required. The EPA has yet to set this threshold. This rule affects some of our and our customers’ largest new or modified facilities going forward.
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Although it is not currently possible to predict how any proposed or future greenhouse gas legislation or regulation by Congress, the states or multi-state regions will impact our business, any legislation or regulation of greenhouse gas emissions that may be imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions or reduced demand for our services, and could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Water Discharges
The CWA and analogous state laws and their implementing regulations impose restrictions and strict controls with respect to the discharge of pollutants into state waters or waters of the U.S. 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. In addition, the CWA regulates storm water discharges associated with industrial activities depending on a facility’s primary standard industrial classification. Many of our facilities have applied for and obtained industrial wastewater discharge permits as well as sought coverage under local wastewater ordinances U.S. federal laws also require development and implementation of spill prevention, controls, and countermeasure plans, including appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak at such facilities.
Waste Management and Disposal
The RCRA and analogous state laws and their implementing regulations govern the generation, transportation, treatment, storage and disposal of hazardous and non-hazardous solid wastes. During the course of our operations, we generate wastes (including, but not limited to, used oil, antifreeze, filters, sludges, paints, solvents and abrasive blasting materials) in quantities regulated under RCRA. The EPA and various state agencies have limited the approved methods of disposal for these types of wastes. CERCLA and analogous state laws and their implementing regulations impose strict, and under certain conditions, joint and several liability without regard to fault or the legality of the original conduct on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include current and past owners and operators of the facility or disposal site where the release occurred and any company that transported, disposed of, or arranged for the transport or disposal of the hazardous substances released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up 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 neighboring landowners and other third parties to file claims for personal injury, property damage and recovery of response costs allegedly caused by hazardous substances or other pollutants released into the environment.
We currently own or lease, and in the past have owned or leased, a number of properties that have been used in support of our operations for a number of years. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons, hazardous substances, or other regulated wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such materials have been taken for disposal by companies sub-contracted by us. In addition, many of these properties have been previously owned or operated by third parties whose treatment and disposal or release of hydrocarbons, hazardous substances or other regulated wastes was not under our control. These properties and the materials released or disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove or remediate historical property contamination, or to perform certain operations to prevent future contamination. At certain of such sites, we are currently working with the prior owners who have undertaken to monitor and clean up contamination that occurred prior to our acquisition of these sites. We are not currently under any order requiring that we undertake or pay for any cleanup activities. However, we cannot provide any assurance that we will not receive any such order in the future.
Occupational Safety and Health
We are subject to the requirements of OSHA and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the safety and health of employees. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations.
Employees
As of December 31, 2015, we had approximately 2,200 employees. We believe that our relations with our employees are satisfactory.
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Available Information
Our website address is www.archrock.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports are available on our website, without charge, as soon as reasonably practicable after they are filed electronically with the U.S. Securities and Exchange Commission (“SEC”). Information on our website is not incorporated by reference in this Annual Report on Form 10-K or any of our other securities filings. Paper copies of our filings are also available, without charge, from Archrock, Inc., 16666 Northchase Drive, Houston, Texas 77060, Attention: Investor Relations. Alternatively, the public may read and copy any materials we file with the SEC at its Public Reference Room at 100 F Street, NE, Washington, DC 20549.
Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC also maintains a website that contains reports, proxy and information statements and other information regarding issuers who file electronically with the SEC. The SEC’s website address is www.sec.gov.
Additionally, we make available free of charge on our website:
• | our Code of Business Conduct; |
• | our Corporate Governance Principles; and |
• | the charters of our audit, compensation and nominating and corporate governance committees. |
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Item 1A. Risk Factors
As described in Part I (“Disclosure Regarding Forward-Looking Statements”), this Annual Report on Form 10-K 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 actually occurs, our business, financial condition, results of operations and cash flows could be negatively impacted.
Continued low oil and natural gas prices in the U.S. are expected to decrease demand for our natural gas compression services and result in a decline in our business in 2016, which could decrease our cash available to pay dividends and limit our ability to pay cash dividends at our current dividend rate.
Our revenue, earnings and financial position are affected by, among other things, market conditions that impact demand and pricing for natural gas compression services. For example, the Henry Hub spot price for natural gas was $2.28 per MMBtu at December 31, 2015, which was approximately 8% and 27% lower than prices at September 30, 2015 and December 31, 2014, respectively, and the U.S. natural gas liquid composite price was $4.72 per MMBtu for the month of November 2015, which was approximately 3% and 16% lower than the prices for the months of September 2015 and December 2014, respectively. These price declines have caused many companies to reduce their natural gas drilling and production activities, particularly in more mature and predominantly dry gas areas and shale plays in the U.S., where we provide a significant amount of contract operations services, which led to a decline in our contract operations business during 2015. These price declines are expected to lead to a continued decrease in capital investment and in the number of new gas wells being drilled in 2016 by exploration and production companies. In addition, the West Texas Intermediate crude oil spot price was $37.13 per barrel at December 31, 2015, which was approximately 18% and 31% lower than prices at September 30, 2015 and December 31, 2014, respectively, which is expected to lead to a continued decrease in capital investment and in the number of new oil wells being drilled in 2016 by exploration and production companies. Because we provide a significant amount of contract operations services related to the production of associated gas from oil wells and the use of gas lift to enhance production of oil from oil wells, our operations and our levels of operating horsepower are also impacted by crude oil drilling and production activity.
During periods of lower oil or natural gas prices, our customers may not be able to recover the full amount of their drilling and production costs in the regions in which we operate. As a result, our customers may cease production in existing wells and decline to drill new wells, which would lower their demand for our services. Additionally, some of our midstream customers may provide their gathering, transportation and related services to a limited number of companies in the oil and gas production business. The loss by these midstream customers of their key customers could reduce demand for their services and result in a deterioration of their financial condition, which would in turn decrease their demand for our services. A reduction in the demand for our services could result in our customers seeking to preserve capital by canceling contracts, canceling or delaying scheduled maintenance of their existing equipment or determining not to enter into new contract operations service contracts, which could lead to a reduction in our business activity levels and our pricing, which could have a material adverse effect on our business, financial condition, cash flows and results of operations.
As a result of the significant decline in oil and natural gas prices since the third quarter of 2014, U.S. producers reduced their capital budgets for 2015 and research analysts are forecasting declines in U.S. capital spending for drilling activity in 2016. In 2015, we experienced an operating horsepower decline. Due to the expected continued decrease in customer spending in 2016 and the expectation that our customers will cease production from wells that are uneconomic for them to continue to produce, we anticipate lower demand for our services during 2016 than in 2015. As a result, we expect continued operating horsepower declines in 2016 and we may also experience increased pricing pressure on the services we provide during 2016, which is expected to result in a decline in our contract operations business in 2016. Any of these events could have a material adverse effect on our business, results of operations, financial condition and cash available for distribution to holders of our common stock as a dividend, which could limit our ability to pay cash dividends at our current dividend rate or at all.
While we paid quarterly dividends of $0.15 per share of common stock with respect to each of the first three quarters of 2015 and a quarterly dividend of $0.1875 per share of common stock with respect to the fourth quarter of 2015, there can be no assurance that we will pay dividends in the future.
We paid quarterly cash dividends of $0.15 per share of common stock to our stockholders with respect to each of the first three quarters of 2015, and on February 16, 2016, we paid a quarterly dividend of $0.1875 per share of common stock to our stockholders with respect to the fourth quarter of 2015. We cannot provide assurance that we will, at any time in the future, again generate sufficient surplus cash that would be available for distribution to the holders of our common stock as a dividend or that our Board of Directors would determine to use any such surplus or our net profits to pay a dividend.
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Future dividends may be affected by, among other factors:
• | the availability of surplus or net profits, which in turn depend on the performance of our business and operating subsidiaries, including the Partnership; |
• | the amount of cash distributions we receive from the Partnership attributable to our ownership interest in the Partnership; |
• | our debt service requirements and other liabilities; |
• | our ability to refinance our debt in the future or borrow funds and access capital markets; |
• | restrictions contained in our debt agreements; |
• | our future capital requirements, including to fund our operating expenses and other working capital needs; |
• | the rates we charge for our services; |
• | the level of demand for our services; |
• | the creditworthiness of our customers; |
• | Exterran Corporation’s ability to recover in full, and our ability to receive contributions from Exterran Corporation corresponding to, the remaining proceeds to be paid to Exterran Corporation from PDVSA Gas, S.A., or PDVSA Gas; and |
• | changes in U.S. federal and state income tax laws or corporate laws. |
We also continue to explore ways to reduce our operating expenses. For example, in January 2016, we determined to undertake a cost reduction program in light of current and expected activity levels and to mitigate the impact of the anticipated overall decline in our contract operations business during 2016 as a result of the low commodity price environment. However, achieving significant cost reductions will be challenging, and there is no guarantee that our cost reduction program will result in a reduction in our operating expenses or offset any declines in revenue. Our inability to reduce operating expenses could have an adverse effect on our business, results of operations and financial condition, which could limit our ability to pay cash dividends in the future.
We cannot provide assurance that we will declare or pay dividends in any particular amounts or at all in the future. A decision not to pay dividends or a reduction in our dividend payments in the future could have a negative effect on our stock price.
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We depend on distributions from the Partnership to meet our capital needs and pay dividends to our stockholders.
To generate the funds necessary to meet our obligations, fund our business and pay dividends, we depend heavily on the cash distributions from the Partnership to us attributable to our ownership interest in the Partnership. Our ownership interest in the Partnership, including our limited partner interest, general partner interest and incentive distribution rights in the Partnership, is currently our largest cash-generating asset. As a result, our cash flow is heavily dependent upon the ability of the Partnership to make distributions to its partners. Applicable law and contractual restrictions (including restrictions in the Partnership’s debt instruments and partnership agreement) may negatively impact our ability to obtain such distributions from our subsidiaries, including the rights of the creditors of the Partnership that would often be superior to our interests in the Partnership. Due to the expected continued decrease in customer spending in 2016 and the expectation that customers will cease production from wells that are uneconomic for them to continue to produce, we anticipate lower demand for the Partnership’s contract operations services during 2016 than in 2015. As a result, we expect the Partnership to experience operating horsepower declines in 2016 and it may also experience increased pricing pressure on the services it provides during 2016, which is expected to result in a decline in the Partnership’s contract operations business in 2016. A decline in the Partnership’s business or revenues or increases in its expenses, principal and interest payments under existing and future debt instruments, working capital requirements or other cash needs could impair the Partnership’s ability to make cash distributions to unit holders, including us, at the Partnership’s current distribution rate. A reduction in the amount of cash distributions we receive from the Partnership would reduce the amount of cash available to us for payment of dividends, which could limit our ability to pay cash dividends at our current rate or at all, and would also reduce the amount of cash available to us for the payment of our debt and for the funding of our business requirements, which could have a material adverse effect on our business, financial condition and results of operations.
Exterran Corporation is due to receive a substantial amount in installment payments from the purchaser of its previously nationalized Venezuelan assets, the nonpayment of which would render Exterran Corporation unable to contribute amounts corresponding to those funds to us, which would negatively impact our liquidity and financial condition.
In March 2012 and August 2012, Exterran Corporation sold its previously nationalized Venezuelan joint venture assets and Venezuelan subsidiary assets, respectively, to PDVSA Gas, a subsidiary of Petroleos de Venezuela, S.A. (“PDVSA”), for aggregate consideration of approximately $550 million. As of December 31, 2015, we have received payments, including annual charges, of approximately $493 million ($50 million of which was used to repay insurance proceeds previously collected under the policy we maintained for the risk of expropriation). Pursuant to the separation and distribution agreement, Exterran Corporation or its subsidiary is due to receive the remaining principal amount as of December 31, 2015 of approximately $79 million in installments through the third quarter of 2016. As these remaining proceeds are received, Exterran Corporation intends to contribute to us an amount equal to such proceeds pursuant to the terms of the separation and distribution agreement. In January 2016, Exterran Corporation received an additional installment payment, including an annual charge, of $5.2 million from PDVSA Gas relating to its previously nationalized Venezuelan joint ventures’ assets and transferred cash to us equal to that amount in January 2016.
PDVSA’s payments to many of its suppliers and partners are currently significantly in arrears, and PDVSA’s payments to us have been in arrears from time to time in the past. The ongoing social, political, economic and legal climate has given rise to significant uncertainties about the country’s economic and political stability. Since the presidential election in the first half of 2013, the Venezuelan government has increasingly used foreign-exchange, price and capital controls to attempt to address the country’s economic challenges. If current political unrest were to develop into a prolonged period of governmental or economic instability, or if PDVSA becomes increasingly unable to pay its suppliers and partners due to the detrimental effect of recent commodity price declines on Venezuela’s economy or for other reasons, Exterran Corporation’s ability to recover in full, and our ability to receive additional contributions corresponding to, the remaining proceeds to be paid from PDVSA Gas to Exterran Corporation could be adversely impacted. As of February 29, 2016, PDVSA was in arrears on its payment obligations due to Exterran Corporation. Exterran Corporation has agreed to waive a payment obligation that was due on November, 10 2015 until March 11, 2016, although it is uncertain whether PDVSA will make the past due payment by that date. If Exterran Corporation or its subsidiary does not receive that payment or any other remaining proceeds and we do not receive additional contributions from Exterran Corporation corresponding to the amount of such proceeds, our liquidity and financial condition would be negatively impacted, which could impact our ability to pay cash dividends.
In addition, in the event that PDVSA Gas defaults on any installment payment and Exterran Corporation is unwilling or unable to recover such installment payment, we may incur significant costs and expenses and expend significant resources, including the time and attention of our management team, in pursuing the recovery of such installment payment, which may negatively impact our business and financial condition.
19
We have a substantial amount of debt that could limit our ability to fund future growth and operations and increase our exposure to risk during adverse economic conditions.
At December 31, 2015, we had approximately $1.6 billion in outstanding debt obligations. Many factors, including factors beyond our control, may affect our ability to make payments on our outstanding indebtedness. These factors include those discussed elsewhere in these Risk Factors and those listed in the Disclosure Regarding Forward-Looking Statements section included in Part I of this Annual Report on Form 10-K.
Our substantial debt and associated commitments could have important adverse consequences. For example, these commitments could:
• | make it more difficult for us to satisfy our contractual obligations; |
• | increase our vulnerability to general adverse economic and industry conditions; |
• | limit our ability to fund future working capital, capital expenditures, acquisitions or other corporate requirements; |
• | increase our vulnerability to interest rate fluctuations because the interest payments on a portion of our debt are based upon variable interest rates and a portion can adjust based upon our credit statistics; |
• | limit our flexibility in planning for, or reacting to, changes in our business and our industry; |
• | place us at a disadvantage compared to our competitors that have less debt or less restrictive covenants in such debt; and |
• | limit our ability to refinance our debt in the future or borrow additional funds. |
Covenants in our debt agreements may impair our ability to operate our business.
Our credit facility contains various covenants with which we or certain of our subsidiaries must comply, including, but not limited to, limitations on the incurrence of indebtedness, investments, liens on assets, repurchasing equity and making distributions, transactions with affiliates, mergers, consolidations, dispositions of assets and other provisions customary in similar types of agreements. We are also subject to financial covenants, including a ratio of earnings before interest, taxes, depreciation and amortization (“EBITDA”) (as defined in the credit agreement) to Total Interest Expense (as defined in the credit agreement) of not less than 2.25 to 1.0 and a ratio of consolidated Total Debt (as defined in the credit agreement) to EBITDA of not greater than 4.25 to 1.0 (subject to a temporary increase to 4.75 to 1.0 for any quarter during which an acquisition meeting certain thresholds is completed and for the following two quarters after the acquisition closes). As of December 31, 2015, we maintained a 33.3 to 1.0 EBITDA to Total Interest Expense ratio and a 1.3 to 1.0 consolidated Total Debt to EBITDA ratio. If we were to anticipate non-compliance with these financial ratios, we may take actions to maintain compliance with them, possibly including reductions in our general and administrative expenses, capital expenditures or the payment of cash dividends at our current dividend rate. Any of these measures could have an adverse effect on our business, operations, cash flows or the price of our common stock. If we fail to remain in compliance with our financial covenants we would be in default under our debt agreements. A default under one or more of our debt agreements would trigger cross-default provisions under certain of our other debt agreements, which would accelerate our obligation to repay our indebtedness under those agreements. In addition, if we experience a material adverse effect on our assets, liabilities, financial condition, business or operations, that, taken as a whole, impacts our ability to, perform our obligations under our debt agreements, this could lead to a default under our debt agreements. As of December 31, 2015, we were in compliance with all financial covenants under our debt agreements.
20
The Partnership’s senior secured credit agreement (the “Partnership Credit Agreement”) contains various covenants with which the Partnership must comply, including, but not limited to, restrictions on the use of proceeds from borrowings and limitations on the Partnership’s ability to incur additional indebtedness, engage in transactions with affiliates, merge or consolidate, sell assets, make certain investments and acquisitions, make loans, grant liens, repurchase equity and pay dividends and distributions. The Partnership Credit Agreement also contains various covenants requiring mandatory prepayments from the net cash proceeds of certain asset transfers. The Partnership must maintain various consolidated financial ratios, including a ratio of EBITDA (as defined in the Partnership Credit Agreement) to Total Interest Expense (as defined in the Partnership Credit Agreement) of not less than 2.75 to 1.0, a ratio of Total Debt (as defined in the Partnership Credit Agreement) to EBITDA of not greater than 5.25 to 1.0 (subject to a temporary increase to 5.5 to 1.0 for any quarter during which an acquisition meeting certain thresholds is completed and for the following two quarters after the acquisition closes) and a ratio of Senior Secured Debt (as defined in the Partnership Credit Agreement) to EBITDA of not greater than 4.0 to 1.0. Because the April 2015 Contract Operations Acquisition closed during the second quarter of 2015, the Partnership’s Total Debt to EBITDA ratio threshold was temporarily increased to 5.5 to 1.0 during the quarter ended June 30, 2015 and continued at that level through December 31, 2015, reverting to 5.25 to 1.0 for the quarter ending March 31, 2016 and subsequent quarters. As of December 31, 2015, the Partnership maintained a 4.5 to 1.0 EBITDA to Total Interest Expense ratio, a 4.5 to 1.0 Total Debt to EBITDA ratio and a 2.3 to 1.0 Senior Secured Debt to EBITDA ratio. If the Partnership were to anticipate non-compliance with these financial ratios, the Partnership may take actions to maintain compliance with them, possibly including a reduction in general and administrative expenses, capital expenditures or the payment of cash distributions at its current distribution rate to it unit holders, including us. Any of these measures could have an adverse effect on the Partnership’s business, operations, cash flows or the price of its common units, and as a result could have an adverse impact on us. In addition, a reduction in the amount of cash distributions we receive from the Partnership would reduce the amount of cash available to us for payment of dividends, which could limit our ability to pay cash dividends at our current rate or at all, for the payment of our debt and for the funding of our business requirements, and as a result could have a material adverse effect on our business, financial condition and results of operations. A default under one of the Partnership’s debt agreements would trigger cross-default provisions under the Partnership’s other debt agreements, which would accelerate the Partnership’s obligation to repay its indebtedness under those agreements. In additiona, a material adverse effect with respect to the Partnership’s assets, liabilities, financial condition, business or operations that, taken as a whole, impacts the Partnership’s ability to perform its obligations under the Partnership Credit Agreement, could lead to a default under that agreement. As of December 31, 2015, the Partnership was in compliance with all financial covenants under the Partnership Credit Agreement.
The breach of any of our covenants could result in a default under one or more of our debt agreements, which could cause our indebtedness under those agreements to become due and payable. If the repayment obligations on any of our indebtedness were to be accelerated, we may not be able to repay the debt or refinance the debt on acceptable terms, and our financial position would be materially adversely affected.
As a result of recent market instability, we may be unable to access the capital and credit markets or borrow on affordable terms to obtain additional capital that we may require.
Historically, we have financed acquisitions, operating expenditures and capital expenditures with a combination of cash provided by operating and financing activities. However, to the extent we are unable to finance our operating expenditures, capital expenditures, scheduled interest and debt repayments and any future dividends with net cash provided by operating activities and borrowings under our credit facility, we may require additional capital. Recent instability in the capital markets (both generally and in the oil and gas industry in particular) could limit our ability to access the capital markets to raise debt or equity capital on affordable terms or to obtain additional financing. Recent decreases in commodity prices, among other things, may cause some lenders to increase interest rates, enact tighter lending standards, refuse to refinance existing debt at maturity at favorable terms or at all and may reduce or cease to provide funding to borrowers. If we are unable to access the capital and credit markets on favorable terms, or if we are not successful in raising capital within the time period required or at all, we may not be able to grow or maintain our business, which could have a material adverse effect on our business, results of operations and financial condition.
Our ability to manage and grow our business effectively may be adversely affected if we lose management or operational personnel.
We believe that our ability to hire, train and retain qualified personnel will continue to be challenging and important. In addition, following the closing of the Spin-off, certain of our key personnel became employees of Exterran Corporation. The supply of experienced operational and field personnel, in particular, decreases as other energy and manufacturing companies’ needs for the same personnel increase. Our ability to grow and to continue our current level of service to our customers will be adversely impacted if we are unable to successfully hire, train and retain these important personnel.
21
The erosion of the financial condition of our customers could adversely affect our business.
Many of our customers finance their exploration and production activities through cash flow from operations, the incurrence of debt or the issuance of equity. During times when the oil or natural gas markets weaken, our customers are more likely to experience a downturn in their financial condition. Additionally, some of our midstream customers may provide their gathering, transportation and related services to a limited number of companies in the oil and gas production business. A reduction in borrowing bases under reserve-based credit facilities, the lack of availability of debt or equity financing or other factors that negatively impact our customers’ financial condition could result in a reduction in our customers’ spending for our products and services, which may result in their cancellation of contracts, the cancellation or delay of scheduled maintenance of their existing natural gas compression equipment, their determination not to enter into new natural gas compression service contracts, or their determination to cancel or delay orders for our services. Furthermore, the loss by our midstream customers of their key customers could reduce demand for their services and result in a deterioration of their financial condition, which would in turn decrease their demand for our services. Any such action by our customers would reduce demand for our services. Reduced demand for our services could adversely affect our business, financial condition, results of operations and cash flows. In addition, in the event of the financial failure of a customer, we could experience a loss on all or a portion of our outstanding accounts receivable associated with that customer.
The loss of our business with Williams Partners or the inability or failure of Williams Partners to meet its payment obligations may adversely affect the our and the Partnership’s financial results, which could limit the amount of cash the Partnership has available for distribution to its equity holders, including us.
During the year ended December 31, 2015, Williams Partners (formerly known as Access) accounted for approximately 12% of our consolidated revenue. During the year ended December 31, 2014, Access accounted for approximately 3% of our consolidated revenue. Access merged with Williams Partners, a publicly traded limited partnership controlled by The Williams Companies, Inc. (“Williams Parent”), in February 2015 and, on an as-combined basis, Access and Williams Partners would have accounted for approximately 10% of our consolidated revenue during the year ended December 31, 2014.
On September 28, 2015, Williams Parent and Energy Transfer Equity, L.P. (“ETE”) announced that they had entered into a definitive merger agreement pursuant to which an affiliate of ETE will acquire Williams Parent, and ETE will control Williams Parent and, indirectly, Williams Partners (the “Williams Merger”). There is no guarantee that, upon the expiration of the Partnership’s existing services agreements with Williams Partners, Williams Partners will choose (or, if the Williams Merger closes, ETE will cause Williams Partners) to renew these existing services agreements or enter into similar agreements with the Partnership. The loss of business with Williams Partners, unless offset by additional contract compression services revenue from other customers, or the inability or failure of Williams Partners to meet its payment obligations under contractual arrangements, could have a material adverse effect on the Partnership’s business, results of operations, financial condition and ability to make cash distributions to its equity holders, including us, and on our business, results of operations, financial condition and ability to pay cash dividends.
The completed Spin-off of our international contract operations, international aftermarket services and global fabrication businesses could result in substantial tax liability to us and our stockholders.
Historically, companies seeking to perform a tax-free spin-off transaction have been able to seek broad private letter rulings from the Internal Revenue Service (“IRS”) that the proposed spin-off transaction would qualify for tax-free treatment, with the exception of certain issues on which the IRS would not rule. However, in 2013 the IRS announced that it would no longer provide such broad advance rulings but would instead rule only on certain “significant issues.” We did not request a ruling from the IRS regarding the Spin-off of our international contract operations, international aftermarket services and global fabrication businesses. Prior to completing the Spin-off, we did receive an opinion of counsel that the Spin-off should qualify as reorganization under Sections 355 and 368(a)(1)(D) of the Internal Revenue Code of 1986, as amended (the “Code”), and, as a result, neither we nor our stockholders should recognize any gain or loss for U.S. federal income tax purposes as a result of the Spin-off. However, this opinion is not binding on the IRS or any court. Accordingly, the IRS or the courts may reach conclusions with respect to the Spin-off that are different from the conclusions reached in the opinion of counsel. If the Spin-off and certain related transactions were determined to be taxable to us, we would be subject to a substantial tax liability, which could have a material adverse effect on our business, results of operations and financial condition. In addition, if the Spin-off were taxable to our stockholders, each holder of our common stock who received shares of Exterran Corporation would generally be treated as having received a taxable distribution of property in an amount equal to the fair market value of the shares received.
22
We may face challenges as a result of being a smaller, less diversified business than we were prior to the Spin-off.
In connection with the Spin-off, our international contract operations, international aftermarket services and fabrication operations and certain of our logistical capabilities and operational efficiencies were contributed to Exterran Corporation, and certain of our key personnel became employees of Exterran Corporation. Because our business after the Spin-off represents a subset of our business immediately prior to the Spin-off, we have access to a smaller pool of assets, fewer personnel, less geographic diversity and less operational diversity, among other challenges, than we did prior to the Spin-off. As a result, we are a smaller and less diversified company with more limited financial resources and operational capabilities, and we may be unable to attract or retain customers that prefer to contract with more diversified companies that are able to operate on a larger scale than us. In addition, as a smaller and less diversified business, we may be more adversely impacted by changes in our business than we would have been prior to the Spin-off. For example, the impact of certain events on our business prior to the Spin-off may not have been material to our operations at such time, but similar events may have a material impact on our business following the Spin-off. We may also be less capable of providing the Partnership with certain financial and operational support, including certain historical cost caps that we provided to the Partnership prior to 2015, that we were capable of providing to the Partnership prior to the Spin-off. In addition, because we are a smaller and less diversified business following the Spin-off, certain legal proceedings may have greater impact on our business following the Spin-off than they did before the Spin-off. Each of these events could negatively impact our business and cause our financial condition and results of operations to suffer.
We are subject to continuing contingent tax liabilities following the Spin-off.
In connection with the Spin-off, we entered into a tax matters agreement with Exterran Corporation that allocates the responsibility for prior period taxes of the Exterran Holdings consolidated tax reporting group between us and Exterran Corporation. If Exterran Corporation is unable to pay any prior period taxes for which it is responsible, we would be required to pay the entire amount of such taxes.
We might not be able to engage in desirable strategic transactions and equity issuances because of certain restrictions relating to requirements for tax-free distributions.
Our ability to engage in significant equity transactions could be limited or restricted in order to preserve, for U.S. federal income tax purposes, the tax-free nature of the Spin-off. Even if the Spin-off otherwise qualifies for tax-free treatment under Section 355 of the Code, it may result in corporate-level taxable gain to us under Section 355(e) of the Code if there is a 50% or greater change in ownership, by vote or value, of shares of our stock, Exterran Corporation’s stock or the stock of a successor of either occurring as part of a plan or series of related transactions that includes the Spin-off. Any acquisitions or issuances of our stock or Exterran Corporation’s stock within two years after the Spin-off are generally presumed to be part of such a plan, although we or Exterran Corporation may be able to rebut that presumption.
Under the tax matters agreement that we entered into with Exterran Corporation, we are prohibited from taking or failing to take any action that prevents the Spin-off from being tax-free.
These restrictions may limit our ability to pursue strategic transactions or engage in new business or other transactions that may maximize the value of our business. Moreover, the tax matters agreement also may provide that we are responsible for any taxes imposed on us or any of our affiliates as a result of the failure of the Spin-off to qualify for favorable treatment under the Code if such failure is attributable to certain actions taken after the Spin-off by or in respect of us, any of our affiliates or our shareholders.
23
The Spin-off may expose us to potential liabilities arising out of state and federal fraudulent conveyance laws and legal dividend requirements.
The Spin-off is subject to review under various state and federal fraudulent conveyance laws. Under these laws, if a court in a lawsuit by an unpaid creditor or an entity vested with the power of such creditor (including without limitation a trustee or debtor-in-possession in a bankruptcy by us or any of our respective subsidiaries) were to determine that we or any of our subsidiaries did not receive fair consideration or reasonably equivalent value for distributing our common stock or taking other action as part of the Spin-off, or that we or any of our subsidiaries did not receive fair consideration or reasonably equivalent value for incurring indebtedness, including the borrowings incurred by us under the new credit facility in connection with the Spin-off, transferring assets or taking other action as part of the Spin-off and, at the time of such action, we, Exterran Corporation or any of our respective subsidiaries (i) was insolvent or would be rendered insolvent, (ii) lacked reasonably sufficient capital to carry on its business and all business in which it intended to engage or (iii) intended to incur, or believed it would incur, debts beyond its ability to repay such debts as they would mature, then such court could void the Spin-off as a constructive fraudulent transfer. If such court made this determination, the court could impose a number of different remedies, including without limitation, voiding our liens and claims against Exterran Corporation, or providing Exterran Corporation with a claim for money damages against us in an amount equal to the difference between the consideration received by Exterran Corporation and the fair market value of our company at the time of the Spin-off.
The measure of insolvency for purposes of the fraudulent conveyance laws will vary depending on which jurisdiction’s law is applied. Generally, however, an entity would be considered insolvent if the present fair saleable value of its assets is less than (i) the amount of its liabilities (including contingent liabilities) or (ii) the amount that will be required to pay its probable liabilities on its existing debts as they become absolute and mature. No assurance can be given as to what standard a court would apply to determine insolvency or that a court would determine that we, Exterran Corporation or any of our respective subsidiaries were solvent at the time of or after giving effect to the Spin-off, including the distribution of the Exterran Corporation common stock.
Under the separation and distribution agreement we entered into in connection with the Spin-off, from and after the Spin-off, each of Exterran Corporation and we are responsible for the debts, liabilities and other obligations related to the business or businesses which it owns and operates following the consummation of the Spin-off. Although we do not expect to be liable for any such obligations not expressly assumed by us pursuant to the separation and distribution agreement, it is possible that a court would disregard the allocation agreed to between the parties, and require that we assume responsibility for obligations allocated to Exterran Corporation, particularly if Exterran Corporation were to refuse or were unable to pay or perform the subject allocated obligations.
Many of our contract operations services contracts have short initial terms and after the initial term are cancelable on short notice, and we cannot be sure that such contracts will be extended or renewed after the end of the initial contractual term. Any such nonrenewals, or renewals at reduced rates, or the loss of contracts with any significant customer, could adversely impact our results of operations.
The length of our contract operations services contracts with customers varies based on operating conditions and customer needs. Our initial contract terms typically are not long enough to enable us to recoup the cost of the equipment we utilize to provide contract operations services and these contracts are typically cancelable on short notice after the initial term. We cannot be sure that a substantial number of these contracts will be extended or renewed by our customers or that any of our customers will continue to contract with us. The inability to negotiate extensions or renew a substantial portion of our contract operations services contracts, the renewal of such contracts at reduced rates, the inability to contract for additional services with our customers or the loss of all or a significant portion of our services contracts with any significant customer could lead to a reduction in revenues and net income and could require us to record additional asset impairments. This could have a material adverse effect upon our business, financial condition, results of operations and cash flows.
24
We are engaged in ongoing litigation regarding our qualification as a Heavy Equipment Dealer, the qualification of our natural gas compressors as Heavy Equipment and the resulting appraisal of our natural gas compressors for ad valorem tax purposes, as well as the location where our natural gas compressors are taxable, under revised Texas statutes. If this litigation is resolved against us, or if in the future we do not qualify as a Heavy Equipment Dealer or our compressors do not qualify as Heavy Equipment because of new or revised Texas statutes, we will incur additional taxes and could be subject to substantial penalties and interest, which would adversely impact our results of operations, financial condition and cash flows.
In 2011, the Texas Legislature enacted changes related to the appraisal of natural gas compressors for ad valorem tax purposes by expanding the definitions of “Heavy Equipment Dealer” and “Heavy Equipment” effective from the beginning of 2012 (the “Heavy Equipment Statutes”). Under the revised statutes, we believe we are a Heavy Equipment Dealer, that our natural gas compressors are Heavy Equipment and that we, therefore, are required to file our ad valorem tax renditions under this new methodology. We further believe that, under the Heavy Equipment Statutes, our natural gas compressors are taxable in the counties where we maintain a business location and keep natural gas compressors. A large number of appraisal review boards denied our position, and we filed petitions for review in the appropriate district courts. See Part I, Item 3 (“Legal Proceedings”) and Note 20 (“Commitments and Contingencies”) to our Financial Statements included in this Annual Report on Form 10-K for additional information regarding legal proceedings to which we are a party, including ongoing litigation regarding our qualification as a Heavy Equipment Dealer, the qualification of our natural gas compressors as Heavy Equipment and the resulting appraisal of our natural gas compressors for ad valorem tax purposes, as well as the location where our natural gas compressors are taxable, under revised Texas statutes.
As a result of the new methodology, our ad valorem tax expense (which is reflected in our consolidated statements of operations as a component of cost of sales (excluding depreciation and amortization expense)) includes a benefit of $16.0 million during the year ended December 31, 2015. Since the change in methodology became effective in 2012, we have recorded an aggregate benefit of $44.0 million as of December 31, 2015, of which approximately $10.2 million has been agreed to by a number of appraisal review boards and county appraisal districts and $33.8 million has been disputed and is currently in litigation. Recognizing the similarity of the issues and that these cases will ultimately be resolved by the Texas appellate courts, we have reached, or intend to reach, agreements with some of the appraisal districts to stay or abate certain of these pending district court cases. If we are unsuccessful in our litigation with the appraisal districts, we would be required to pay ad valorem taxes up to the aggregate benefit we have recorded, and the additional ad valorem tax payments may also be subject to substantial penalties and interest. In addition, while we do not expect the ultimate determination of the issue of where the natural gas compressors are taxable under the Heavy Equipment Statutes would have an impact on the amount of taxes due, we could be subject to substantial penalties if we are unsuccessful on this issue. Also, if we are unsuccessful in our litigation with the appraisal districts, or if legislation is enacted in Texas that repeals or alters the Heavy Equipment Statutes such that in the future we do not qualify as a Heavy Equipment Dealer or our compressors do not qualify as Heavy Equipment, then we would likely be required to pay these ad valorem taxes under the old methodology going forward, which would increase our quarterly cost of sales expense up to approximately the amount of our then most recent quarterly benefit recorded. If this litigation is resolved against us in whole or in part, or if in the future we do not qualify as a Heavy Equipment Dealer or our compressors do not qualify as Heavy Equipment because of new or revised Texas statutes, we will incur additional taxes and could be subject to substantial penalties and interest, which would impact our future results of operations, financial condition and cash flows and also our ability to pay dividends in the future.
25
As a result of our supply agreement with Exterran Corporation, we are subject to counterparty risk associated with Exterran Corporation’s business, including product shortages and price increases involving Exterran Corporation’s suppliers, which could have a negative impact on our results of operations. Additionally, if we are unable to purchase compression equipment from Exterran Corporation or other third parties, we may be unable to retain existing customers or compete for new customers, which could have a material adverse effect on our business, results of operations and financial condition.
Under the terms of our supply agreement with Exterran Corporation, we are required to purchase our requirements of newly-fabricated compression equipment during the term of the agreement from Exterran Corporation and its affiliates, subject to certain exceptions. As a result, we are subject to many of the same counterparty risks as Exterran Corporation with respect to its suppliers. For example, certain of the components used in the compression equipment we expect to purchase from Exterran Corporation are obtained by Exterran Corporation from a single source or a limited group of suppliers. Exterran Corporation’s reliance on these suppliers involves several risks, including price increases, inferior component quality and a potential inability to obtain an adequate supply of required components in a timely manner. Exterran Corporation does not have long-term contracts with some of these sources, and the partial or complete loss of certain of these sources could have a negative impact on our ability to obtain compression equipment from Exterran Corporation which, in turn, could have a negative impact on our results of operations, reputation and customer relationships. Further, any increase in component prices for compression equipment fabricated by Exterran Corporation for us will be passed on to us under the terms of our supply agreement. As a result, a significant increase in the price of one or more of these components could have a negative impact on our results of operations.
Additionally, except as set forth in our supply agreement, Exterran Corporation is not under any obligation to offer or sell to us newly-fabricated compression equipment, and may choose not to sell such equipment to us on time or at all. In the event that we are not able to purchase compression equipment from Exterran Corporation, we may not be able to purchase such compression equipment from third-party producers or marketers of such equipment or from our competitors on comparable terms or at all. If we are unable to purchase compression equipment on a timely basis to meet the demands of our customers, our existing customers may terminate their contractual relationships with us, or we may not be able to compete for business from new or existing customers, which, in each case, could have a material adverse effect on our business, results of operations and financial condition.
We have the right to receive a cash payment from Exterran Corporation upon the refinancing of its term loan under certain conditions, which if not met would negatively impact our liquidity and financial condition.
In October 2015, a subsidiary of Exterran Corporation entered into a new $245.0 million term loan, which will mature on November 3, 2017. Exterran Corporation or its subsidiary will be required to refinance its term loan at or prior to its maturity date by entering into one or more new facilities or otherwise raising the funds necessary to repay the outstanding principal amount under the term loan. In connection with the Spin-off, Exterran Corporation’s operating subsidiary contributed to one of our subsidiaries the right to receive, promptly following the occurrence of a qualified capital raise, as that term is used in the separation and distribution agreement, the right to receive a $25.0 million cash payment. No assurance can be given that Exterran Corporation or its subsidiary will be able to enter into new facilities or issue equity in the future on attractive terms or at all. If Exterran Corporation or its subsidiary is unable to consummate a qualified capital raise, we will not receive the $25.0 million cash payment, which would negatively impact our liquidity and financial condition.
The tax treatment of publicly traded partnerships or our investment in the Partnership units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.
The anticipated after-tax economic benefit of our investment in the Partnership depends largely on it being treated as a partnership for U.S. federal income tax purposes. The present U.S. federal income tax treatment of publicly traded partnerships, including the Partnership, or our investment in the Partnership may be modified by administrative, legislative or judicial changes or differing interpretations at any time.
For example, from time to time, members of Congress propose and consider such substantive changes to the existing U.S. federal income tax laws that affect 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 the Partnership relies for its treatment as a partnership for U.S. federal income tax purposes. Despite the fact that the Partnership is organized as a limited partnership under Delaware law, it would be treated as a corporation for U.S. federal income tax purposes unless at least 90% of its gross income is ‘‘qualifying income’’ under Section 7704(d)(1)(E) of the Internal Revenue Code of 1986, as amended (the ‘‘Qualifying Income Exception’’).
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The Partnership has requested and obtained favorable private letter rulings from the IRS with respect to the characterization of certain of its income as qualifying income. However, on May 5, 2015, the U.S. Treasury Department and the IRS issued proposed regulations (the ‘‘Proposed Regulations’’) interpreting the scope of qualifying income. The Proposed Regulations provide industry-specific guidance regarding whether income earned from certain activities will generate qualifying income for purposes of the Qualifying Income Exception. The Proposed Regulations, once issued in final form, may change interpretations of the current law relating to the characterization of income as qualifying income. Any such change could result in some or all of the Partnership’s income being treated as non-qualifying income.
Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for the Partnership to meet the exception for certain publicly traded partnerships to be treated as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be finalized or enacted. Any such changes could cause the Partnership to be treated as a corporation for U.S. federal income tax purposes or otherwise subject it to taxation as an entity if its gross income is not properly classified as qualifying income.
If the Partnership were treated as a corporation for U.S. federal income tax purposes, its cash available for distribution, including to us as holders of Partnership units, would be substantially reduced. Further, distributions to unitholders, including us, would generally be taxed as corporate distributions, and no income, gains, losses or deductions would flow through to unitholders.
Therefore, treatment of the Partnership as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, which would cause a substantial reduction in the value of our investment in the Partnership and in the amount of distributions that we receive from the Partnership, which would reduce the amount of cash available for payment of our debt, payment of dividends and the funding of our business requirements, and as a result could have a material adverse effect on our business, financial condition and results of operations.
We may not be able to consummate any additional contribution or sale of assets from our contract operations business to the Partnership.
In the future, we may transfer additional assets from our contract operations business to the Partnership, but we are under no obligation to do so. Likewise, the Partnership is under no obligation to purchase any additional assets of that business. The consummation of any future sale of additional assets from that business and the timing of any such sale will depend upon, among other things:
• | our agreement with the Partnership regarding the terms of such sale, which will require the approval of the conflicts committee of the board of directors of the Partnership’s general partner, which is comprised exclusively of independent directors; |
• | the Partnership’s ability to finance such purchase on acceptable terms, which could be impacted by general equity and debt market conditions as well as conditions in the markets specific to master limited partnerships; and |
• | the Partnership’s and our compliance with our respective debt agreements. |
The Partnership may fund any future acquisition from us with external sources of capital, including additional borrowings under its credit facility and/or public or private offerings of equity or debt. If the Partnership is not able to fund a future acquisition of our contract operations business, or if we are otherwise unable to consummate an additional contribution or sale of assets from our contract operations business to the Partnership, the Partnership’s ability to maintain distributions to its unitholders, including us, may be limited.
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From time to time, we are subject to various claims, litigation and other proceedings that could ultimately be resolved against us, requiring material future cash payments or charges, which could impair our financial condition or results of operations.
The size, nature and complexity of our business make us susceptible to various claims, both in litigation and binding arbitration proceedings. We are currently, and may in the future become, subject to various claims, which, if not resolved within amounts we have accrued, could have a material adverse effect on our financial position, results of operations or cash flows, including our ability to make cash distributions to our unitholders. Similarly, any claims, even if fully indemnified or insured, could negatively impact our reputation among our customers and the public, and make it more difficult for us to compete effectively or obtain adequate insurance in the future. See Part I, Item 3 (“Legal Proceedings”) and also Note 20 (“Commitments and Contingencies”) to our Financial Statements included in this Annual Report on Form 10-K for additional information regarding certain legal proceedings to which we are a party, including ongoing litigation regarding our qualification as a heavy equipment dealer, the qualification of our natural gas compressors as heavy equipment and the resulting appraisal of our natural gas compressors for ad valorem tax purposes, as well as the location where our natural gas compressors are taxable, under revised Texas statutes.
We face significant competitive pressures that may cause us to lose market share and harm our financial performance.
Our business is highly competitive and there are low barriers to entry, especially our natural gas compression services. Our competitors may be able to adapt more quickly to technological changes within our industry and changes in economic and market conditions, more readily take advantage of acquisitions and other opportunities and adopt more aggressive pricing policies. Our ability to renew or replace existing contract operations service contracts with our customers at rates sufficient to maintain current revenue and cash flows could be adversely affected by the activities of our competitors. If our competitors substantially increase the resources they devote to the development and marketing of competitive products, equipment or services or substantially decrease the price at which they offer their products, equipment or services, we may not be able to compete effectively.
In addition, we could face significant competition from new entrants into the compression services business. Some of our existing competitors or new entrants may expand or fabricate new compression units that would create additional competition for the services we provide to our customers. In addition, our customers may purchase and operate their own compressor fleets in lieu of using our natural gas compression services. We also may not be able to take advantage of certain opportunities or make certain investments because of our debt levels and our other obligations. Any of these competitive pressures could have a material adverse effect on our business, financial condition and results of operations.
We may be vulnerable to interest rate increases due to our floating rate debt obligations.
As of December 31, 2015, after taking into consideration interest rate swaps, we had $397.0 million of outstanding indebtedness that was effectively subject to floating interest rates. Changes in economic conditions outside of our control could result in higher interest rates, thereby increasing our interest expense and reducing the funds available for capital investment, operations or other purposes. A 1% increase in the effective interest rate on our outstanding debt subject to floating interest rates at December 31, 2015 would result in an annual increase in our interest expense of approximately $4.0 million. In addition, a substantial portion of the Partnership’s cash flow must be used to service its debt obligations. Any increase in the Partnership’s interest expense could reduce the amount of cash the Partnership has available for distribution to its equity holders, including us, and as a result negatively impact our results of operations and cash flows and also our ability to pay dividends in the future.
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Our operations entail inherent risks that may result in substantial liability. We do not insure against all potential losses and could be seriously harmed by unexpected liabilities.
Our operations entail inherent risks, including equipment defects, malfunctions and failures and natural disasters, which could result in uncontrollable flows of natural gas or well fluids, fires and explosions. These risks may expose us, as an equipment operator, to liability for personal injury, wrongful death, property damage, pollution and other environmental damage. The insurance we carry against many of these risks may not be adequate to cover our claims or losses. We currently have a minimal amount of insurance on our offshore assets. In addition, we are substantially self-insured for workers’ compensation, employer’s liability, property, auto liability, general liability and employee group health claims in view of the relatively high per-incident deductibles we absorb under our insurance arrangements for these risks. Further, insurance covering the risks we expect to 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, financial condition and results of operations could be negatively impacted.
Threats of cyber attacks or terrorism could affect our business.
We may be threatened by problems such as cyber attacks, computer viruses or terrorism that may disrupt our operations and harm our operating results. Our industry requires the continued operation of sophisticated information technology systems and network infrastructure. Despite our implementation of security measures, our technology systems are vulnerable to disability or failures due to hacking, viruses, acts of war or terrorism and other causes. If our information technology systems were to fail and we were unable to recover in a timely way, we might be unable to fulfill critical business functions, which could have a material adverse effect on our business, financial condition and results of operations.
In addition, our assets may be targets of terrorist activities that could disrupt our ability to service our customers. We may be required by our regulators or by the future terrorist threat environment to make investments in security that we cannot currently predict. The implementation of security guidelines and measures and maintenance of insurance, to the extent available, addressing such activities could increase costs. These types of events could materially adversely affect our business and results of operations. In addition, these types of events could require significant management attention and resources, and could adversely affect our reputation among customers and the public.
Tax legislation and administrative initiatives or challenges to our tax positions could adversely affect our results of operations and financial condition.
We operate in locations throughout the United States and, as a result, we are subject to the tax laws and regulations of U.S. federal, state, and local governments. From time to time, various legislative or administrative initiatives may be proposed that could adversely affect our tax positions. There can be no assurance that our tax provision or tax payments will not be adversely affected by these initiatives. In addition, U.S. federal, state and local tax laws and regulations are extremely complex and subject to varying interpretations. There can be no assurance that our tax positions will not be challenged by relevant tax authorities or that we would be successful in any such challenge.
U.S. Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect demand for our contract operations services.
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into target geological formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing is typically regulated by state agencies, but recently, there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies, and proposals have been made to enact separate U.S. federal, state and local legislation that would increase the regulatory burden imposed on hydraulic fracturing.
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For example, at the U.S. federal level, the U.S. Environmental Protection Agency (“EPA”) issued an Advance Notice of Proposed Rulemaking to collect data on chemicals used in hydraulic fracturing operations under Section 8 of the Toxic Substances Control Act, and proposed regulations under the CWA governing wastewater discharges from hydraulic fracturing and certain other natural gas operations. On March 26, 2015, the U.S. Department of the Interior’s Bureau of Land Management released a final rule that updates existing regulation of hydraulic fracturing activities on U.S. federal lands, including requirements for chemical disclosure, wellbore integrity and handling of flowback water. The final rule was expected to be effective on June 24, 2015, but, on September 30, 2015, a federal district court issued a preliminary injunction preventing implementation of the rule. In addition, several governmental reviews are underway that focus on environmental aspects of hydraulic fracturing activities. In June 2015, the EPA released its draft report on the potential impacts of hydraulic fracturing on drinking water resources, which concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water sources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water sources. The draft report is expected to be finalized after a public comment period and a formal review by EPA’s Science Advisory Board. In addition, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The results of this study or similar governmental reviews could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act of 1974 or otherwise.
At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example in May 2013, the Texas Railroad Commission adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. Local governments may also seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. If new or more stringent U.S. federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where our natural gas exploration and production customers operate, those customers could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities and perhaps even be precluded from drilling wells. Any such restrictions could reduce demand for our contract operations services, and as a result could have a material adverse effect on our business, financial condition, results of operations and cash flows.
New regulations, proposed regulations and proposed modifications to existing regulations under the CAA, if implemented, could result in increased compliance costs.
On September 18, 2015, the EPA issued proposed regulations that would amend the New Source Performance Standards (“NSPS”) for the oil and natural gas source category and would apply to sources of emissions of methane and volatile organic compounds (“VOC”) from certain processes, activities and equipment that is constructed, modified or reconstructed after that date. Specifically, the proposed regulation contains both methane and VOC standards for several emission sources not currently covered by the NSPS, such as fugitive emissions from compressor stations and pneumatic pumps and methane standards for certain emission sources that are already regulated for VOC, such as equipment leaks at natural gas processing plants. The proposed amendments also establish methane standards for a subset of equipment that the current NSPS regulates, including reciprocating compressors and pneumatic controllers, and extend the current VOC standards to the remaining unregulated equipment. At this point, we cannot predict whether any such proposed regulations would require us to incur material costs.
On January 22, 2016, the U.S. Department of the Interior’s Bureau of Land Management proposed a new regulation to reduce venting and flaring on federal lands. If adopted as proposed, the regulation would require leak detection inspections at compressor stations and would impose requirements to reduce emissions from pneumatic controllers, among other things. At this point, we cannot predict whether the proposed regulation would require us to incur material costs.
On October 1, 2015, the EPA issued a new National Ambient Air Quality Standards (“NAAQS”) ozone standard of 70 parts per billion (ppb), which is a reduction from the 75 ppb standard set in 2008. This new standard became effective on December 28, 2015. The states are expected to establish revised attainment/non-attainment regions based on the revised ozone standard by approximately October 2017, utilizing air quality data collected between 2014 and 2016. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our customers’ ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant.
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In addition, in January 2011, the Texas Commission on Environmental Quality (“TCEQ”) finalized revisions to certain air permit programs that significantly increase air emissions-related requirements for new and certain existing oil and gas production and gathering sites in the Barnett Shale production area. The final rule established 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, and the lower emissions standards will become applicable between 2020 and 2030 depending on the type of engine and the permitting requirements. A number of other states where our engines are operated have adopted or are considering adopting additional regulations that could impose new air permitting or pollution control requirements for engines, some of which could entail material costs to comply. At this point, however, we cannot predict whether any such rules would require us to incur material costs.
These new regulations and proposals, when finalized, and any other new regulations requiring the installation of more sophisticated pollution control equipment or the adoption of other environmental protection measures, could have a material adverse impact on our business, financial condition, results of operations and cash flows.
We are subject to a variety of governmental regulations; failure to comply with these regulations may result in administrative, civil and criminal enforcement measures and changes in these regulations could increase our costs or liabilities.
We are subject to a variety of U.S. federal, state, and local laws and regulations relating to, for example, the environment, safety and health, export controls, labor and employment and taxation. Many of these laws and regulations are complex, change frequently, are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. Failure to comply with these laws and regulations may result in a variety of administrative, civil and criminal enforcement measures, including assessment of monetary penalties, imposition of remedial requirements and issuance of injunctions as to future compliance.
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, profitability and 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 may need to apply for or amend facility permits or licenses from time to time with respect to storm water or wastewater discharges, waste handling, or air emissions relating to manufacturing activities or equipment operations, which subjects us to new or revised permitting conditions that may be onerous or costly to comply with. In addition, certain of our customer service arrangements may require us to operate, on behalf of a specific customer, petroleum storage units such as underground tanks or pipelines and other regulated units, all of which may impose additional compliance and permitting obligations.
We conduct operations at numerous facilities in a wide variety of locations across the continental U.S. The operations at many of these facilities require environmental permits or other authorizations. Additionally, natural gas compressors at many of our customers’ facilities 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 large number of facilities 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. Occasionally, we have been assessed penalties for our non-compliance, and we could be subject to such penalties 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 contract operations services or inactive compression 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 environmental laws and regulations.
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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.
Climate change legislation and regulatory initiatives could result in increased compliance costs.
The U.S. Congress has previously considered legislation to restrict or regulate emissions of greenhouse gases, such as carbon dioxide and methane. One bill, passed by the House of Representatives in 2009, but never adopted by the full Congress, would have required greenhouse gas emissions reductions by covered sources of as much as 17% from 2005 levels by 2020 and by as much as 83% by 2050. 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 continue to be proposed that may be relevant to greenhouse gas emissions issues. In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address greenhouse gas emissions, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs. Although most of the state-level initiatives have to date been focused on large sources of greenhouse gas emissions, such as electric power plants, it is possible that smaller sources such as our gas-fired compressors could become subject to greenhouse gas-related regulation. Depending on the particular program, we could be required to control emissions or to purchase and surrender allowances for greenhouse gas emissions resulting from our operations.
Independent of Congress, the EPA has been pursuing regulations controlling greenhouse gas emissions under its existing CAA authority. The EPA has adopted rules requiring many facilities, including petroleum and natural gas systems, to inventory and report their greenhouse gas emissions. These reporting obligations were triggered for some sites we operated in 2015.
In addition, the EPA in June 2010 published a final rule providing for the tailored applicability of air permitting requirements for greenhouse gas emissions. The EPA reported that the rulemaking was necessary because without it certain permitting requirements would apply as of January 2011 at an emissions level that would have greatly increased the number of required permits and, among other things, imposed undue costs on small sources and overwhelmed the resources of permitting authorities. In the rule, the EPA established two initial steps of phase-in to minimize those burdens, excluding certain smaller sources from greenhouse gas permitting until at least April 30, 2016. On January 2, 2011, the first step of the phase-in applied only to new projects at major sources (as defined under those CAA permitting programs) that, among other things, increase net greenhouse gas emissions by 75,000 tons per year. On July 1, 2011, the second step of the phase-in began requiring permitting for otherwise minor sources of air emissions that have the potential to emit at least 100,000 tons per year of greenhouse gases. On June 29, 2012, the EPA issued final regulations for “Phase III” of its program, retaining the permitting thresholds established in Phases I and II. On June 23, 2014, the U.S. Supreme Court held that greenhouse gas emissions alone cannot trigger an obligation to obtain such an air permit even if the project will substantially increase the source’s greenhouse gas emissions. However, for those sources that trigger such air permitting requirements based on their traditional criteria pollutant emissions, the permit must include a limit for greenhouse gases. In addition, the Court concluded that the rule was flawed because the EPA failed to identify a de minimis threshold for greenhouse gases below which Best Available Control Technology would not be required. The EPA has yet to set this threshold. This rule affects some of our and our customers’ largest new or modified facilities going forward.
Although it is not currently possible to predict how any proposed or future greenhouse gas legislation or regulation by Congress, the states or multi-state regions will impact our business, any legislation or regulation of greenhouse gas emissions that may be imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions or reduced demand for our services, and could have a material adverse effect on our business, financial condition, results of operations and cash flows.
The price of our common stock and the Partnership’s common units may be volatile.
Some of the factors that could affect the price of our common stock are quarterly increases or decreases in revenue or earnings, the amount of distributions we receive from the Partnership, the amount of dividend payments we make, changes in interest rates, changes in revenue or earnings estimates by the investment community and speculation in the press or investment community about our financial condition or results of operations. General market conditions and U.S. or international economic factors and political events unrelated to our performance may also affect our stock price. In addition, the price of our common stock may be impacted by changes in the value of our investment in and/or distributions from the Partnership. For these reasons, investors should not rely on recent trends in the price of our common stock to predict the future price of our common stock or our financial results.
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Our charter and bylaws contain provisions that may make it more difficult for a third party to acquire control of us, even if a change in control would result in the purchase of our stockholders’ shares of common stock at a premium to the market price or would otherwise be beneficial to our stockholders.
There are provisions in our restated certificate of incorporation and bylaws that may make it more difficult for a third party to acquire control of us, even if a change in control would result in the purchase of our stockholders’ shares of common stock at a premium to the market price or would otherwise be beneficial to our stockholders. For example, our restated certificate of incorporation authorizes the board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, provisions of our restated certificate of incorporation and bylaws, such as limitations on stockholder actions by written consent and on stockholder proposals at meetings of stockholders, could make it more difficult for a third party to acquire control of us. Delaware corporation law may also discourage takeover attempts that have not been approved by the board of directors.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
The following table describes the material facilities we owned or leased as of December 31, 2015:
Location | Status | Square Feet | Uses | ||||
Houston, Texas | Leased | 140,848 | Corporate office | ||||
Oklahoma City, Oklahoma | Leased | 41,250 | Contract operations and aftermarket services | ||||
Yukon, Oklahoma | Owned | 72,000 | Contract operations and aftermarket services | ||||
Belle Chase, Louisiana | Owned | 35,000 | Contract operations and aftermarket services | ||||
Casper, Wyoming | Owned | 28,390 | Contract operations and aftermarket services | ||||
Davis, Oklahoma | Owned | 393,870 | Contract operations and aftermarket services | ||||
Farmington, New Mexico | Owned | 42,097 | Contract operations and aftermarket services | ||||
Houma, Louisiana | Owned | 60,000 | Contract operations and aftermarket services | ||||
Kilgore, Texas | Owned | 32,995 | Contract operations and aftermarket services | ||||
Midland, Texas | Owned | 53,300 | Contract operations and aftermarket services | ||||
Midland, Texas | Owned | 22,180 | Contract operations and aftermarket services | ||||
Pampa, Texas | Leased | 24,000 | Contract operations and aftermarket services | ||||
Victoria, Texas | Owned | 59,852 | Contract operations and aftermarket services | ||||
Broussard, Louisiana | Owned | 74,402 | Contract operations and aftermarket services | ||||
Our executive offices are located at 16666 Northchase Drive, Houston, Texas 77060, and our telephone number is (281) 836-8000.
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Item 3. Legal Proceedings
In 2011, the Texas Legislature enacted changes related to the appraisal of natural gas compressors for ad valorem tax purposes by expanding the definitions of “Heavy Equipment Dealer” and “Heavy Equipment” effective from the beginning of 2012 (the “Heavy Equipment Statutes”). Under the revised statutes, we believe we are a Heavy Equipment Dealer, that our natural gas compressors are Heavy Equipment and that we, therefore, are required to file our ad valorem tax renditions under this new methodology. We further believe that our natural gas compressors are taxable under the Heavy Equipment Statutes in the counties where we maintain a business location and keep natural gas compressors instead of where the compressors may be located on January 1 of a tax year. As a result of this new methodology, our ad valorem tax expense (which is reflected in our consolidated statements of operations as a component of cost of sales (excluding depreciation and amortization expense)) includes a benefit of $16.0 million during the year ended December 31, 2015. Since the change in methodology became effective in 2012, we have recorded an aggregate benefit of $44.0 million as of December 31, 2015. A large number of appraisal review boards denied our position, although some accepted it, and we filed 94 petitions for review in the appropriate district courts with respect to the 2012 tax year, 99 petitions for review in the appropriate district courts with respect to the 2013 tax year, 98 petitions for review in the appropriate district courts with respect to the 2014 tax year, and 90 petitions for review in the appropriate district courts with respect to the 2015 tax year.
To date, only five cases have advanced to the point of trial or submission of summary judgment motions on the merits, and only three cases have been decided, with two of the decisions having been rendered by the same presiding judge. All three of those decisions were appealed, and all three of the appeals have been decided by intermediate appellate courts.
On October 17, 2013, the 143rd Judicial District Court of Loving County, Texas ruled in EXLP Leasing LLC & EES Leasing LLC v. Loving County Appraisal District that our wholly owned subsidiary Archrock Services Leasing LLC, formerly known as EES Leasing LLC (“EES Leasing”), and Archrock Partners’ subsidiary Archrock Partners Leasing LLC, formerly known as EXLP Leasing LLC (“EXLP Leasing”), are Heavy Equipment Dealers and that their compressors qualify as Heavy Equipment, but the district court further held that the Heavy Equipment Statutes were unconstitutional as applied to EES Leasing’s and EXLP Leasing’s compressors. EXLP Leasing and EES Leasing appealed the district court’s constitutionality holding to the Eighth Court of Appeals in El Paso, Texas. On September 23, 2015, the Eighth Court of Appeals ruled in EES Leasing’s and EXLP Leasing’s favor by overruling the 143rd District Court’s constitutionality ruling. The Eighth Court of Appeals also ruled, however, that EES Leasing’s and EXLP Leasing’s natural gas compressors are taxable in the counties where they were located on January 1 of the tax year at issue.
On October 28, 2013, the 143rd Judicial District Court of Ward County, Texas ruled in EES Leasing LLC & EXLP Leasing LLC v. Ward County Appraisal District that EES Leasing and EXLP Leasing are Heavy Equipment Dealers and that their compressors qualify as Heavy Equipment, but the court held that the Heavy Equipment Statutes were unconstitutional as applied to their compressors. EES Leasing and EXLP Leasing appealed the district court’s constitutionality holding to the Eighth Court of Appeals in El Paso, Texas, and the Ward County Appraisal District cross-appealed the district court’s rulings that EES Leasing’s and EXLP Leasing’s compressors qualify as Heavy Equipment. On September 23, 2015, the Eighth Court of Appeals ruled in EES Leasing’s and EXLP Leasing’s favor by overruling the 143rd District Court’s constitutionality ruling and affirming its ruling that EES Leasing’s and EXLP Leasing’s compressors qualify as Heavy Equipment. The Eighth Court of Appeals also ruled, however, that EES Leasing’s and EXLP Leasing’s natural gas compressors are taxable in the counties where they were located on January 1 of the tax year at issue.
On March 18, 2014, the 10th Judicial District Court of Galveston, Texas ruled in EXLP Leasing LLC & EES Leasing LLC v. Galveston Central Appraisal District that EES Leasing and EXLP Leasing are Heavy Equipment Dealers and that their compressors qualify as Heavy Equipment, but the court held the Heavy Equipment Statutes unconstitutional as applied to their compressors. EES Leasing and EXLP Leasing appealed the district court’s constitutionality holding to the Fourteenth Court of Appeals in Houston, Texas. On August 25, 2015, the Fourteenth Court of Appeals issued a ruling stating that EES Leasing’s and EXLP Leasing’s compressors are taxable in the counties where they were located on January 1 of the tax year at issue, and it remanded the case to the district court for further evidence on the issue of whether the Heavy Equipment Statutes are constitutional as applied to EES Leasing’s and EXLP Leasing’s compressors. On November 24, 2015, EES Leasing and EXLP Leasing filed a petition asking the Texas Supreme Court to review this decision. On January 29, 2016, the Texas Supreme Court requested that Galveston Central Appraisal District file a response to EES Leasing’s and EXLP Leasing’s petition for review by February 29, 2016.
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In EES Leasing v. Irion County Appraisal District, EES Leasing and the appraisal district each filed motions for summary judgment in the 51st Judicial District Court of Irion County, Texas concerning the applicability and constitutionality of the Heavy Equipment Statutes. On May 20, 2014, the district court entered an order denying both motions for summary judgment, holding that a fact issue existed as to the applicability of the Heavy Equipment Statutes to the one compressor at issue. The presiding judge for the 51st District Court has since consolidated the 2012 tax year case with EES Leasing’s 2013 tax year case, which also included EXLP Leasing as a party. On August 27, 2015, the presiding judge abated the combined case, EES Leasing LLC and EXLP Leasing LLC v. Irion County Appraisal District, until the final resolution of the appellate cases considering the constitutionality of the Heavy Equipment Statutes, or further order of the court.
EES Leasing and EXLP Leasing also filed a motion for summary judgment in EES Leasing LLC & EXLP Leasing LLC v. Harris County Appraisal District, pending in the 189th Judicial District Court of Harris County, Texas. The court heard arguments on the motion on December 6, 2013 but has yet to rule. No trial date has been set.
On June 3, 2015, the Fourth Court of Appeals in San Antonio, Texas issued a decision reversing the 406th District Court’s dismissal of EES Leasing’s and EXLP Leasing’s tax appeals for want of jurisdiction. In EXLP Leasing LLC et. al v. Webb County Appraisal District, United Independent School District (“United ISD”) intervened as a party in interest and sought to dismiss the lawsuit arguing that the district court was without jurisdiction to hear the appeal. Under Section 42.08(b) of the Texas Tax Code, a property owner must pay before the delinquency date the lesser of (1) the amount of taxes due on the portion of the taxable value of the property that is not in dispute or (2) the amount of taxes due on the property under the order from which the appeal is taken. EES Leasing and EXLP Leasing paid zero taxes to Webb County because the entire amount of tax assessed by Webb County was in dispute. Instead, EES Leasing and EXLP Leasing paid taxes on the compressors at issue to Victoria County, where they maintain their place of business and keep natural gas compressors, which we believe is where the compressors are taxable under the Heavy Equipment Statutes and Texas Comptroller forms. The Webb County Appraisal District and United ISD contested EES Leasing’s and EXLP Leasing’s position, arguing that taxes are payable to the county where each compressor is located as of January 1 of the tax year at issue. The district court granted United ISD’s motion to dismiss on April 1, 2014 and declined EES Leasing’s and EXLP Leasing’s motion to reconsider. The Fourth Court of Appeals reversed, holding that, based on the plain meaning of Section 42.08(b)(1), and because the entire amount was in dispute, EES Leasing and EXLP Leasing were not required to prepay disputed taxes to invoke the trial court’s jurisdiction. The Fourth Court of Appeals denied United ISD’s request for a rehearing. On September 29, 2015, United ISD filed a petition for review in the Texas Supreme Court. On December 4, 2015, the Texas Supreme Court denied United ISD’s petition for review.
United ISD has four delinquency lawsuits pending against EES Leasing and EXLP Leasing in the 49th District Court of Webb County, Texas. The cases have been abated pending the resolution of EES Leasing’s and EXLP Leasing’s 2012 tax year case pending in the 406th Judicial District Court of Webb County, Texas.
We continue to believe that the revised statutes are constitutional as applied to natural gas compressors and that under the revised statutes our natural gas compressors are taxable in the counties where we maintain a business location and keep natural gas compressors. Recognizing the similarity of the issues and that these cases will ultimately be resolved by the Texas appellate courts, we have reached, or intend to reach, agreements with some of the appraisal districts to stay or abate certain of these pending 2012, 2013, 2014, and 2015 district court cases. Please see Note 20 (“Commitments and Contingencies”) to our Financial Statements included in this report for a discussion of our ad valorem tax expense and benefit relating to the Heavy Equipment Statutes, which is incorporated by reference into this Item 3.
In the ordinary course of business, we are also involved in various other pending or threatened legal actions. While management is unable to predict the ultimate outcome of these actions, it believes that any ultimate liability arising from any of these other actions will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. However, because of the inherent uncertainty of litigation, we cannot provide assurance that the resolution of any particular claim or proceeding to which we are a party will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. In addition, because we are a smaller and less diversified business following the Spin-off, certain legal proceedings may have greater impact on our business following the Spin-off than they did before the Spin-off.
Item 4. Mine Safety Disclosures
Not applicable.
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PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is traded on the New York Stock Exchange under the symbol “AROC.” The following table sets forth the range of high and low sale prices for our common stock for the periods indicated.
Price Range | |||||||
High | Low | ||||||
Year Ended December 31, 2014 | |||||||
First Quarter | $ | 44.66 | $ | 33.42 | |||
Second Quarter | $ | 45.90 | $ | 40.81 | |||
Third Quarter | $ | 47.01 | $ | 41.16 | |||
Fourth Quarter | $ | 45.35 | $ | 30.58 | |||
Year Ended December 31, 2015 | |||||||
First Quarter | $ | 34.23 | $ | 26.24 | |||
Second Quarter | $ | 37.71 | $ | 30.14 | |||
Third Quarter | $ | 32.94 | $ | 16.68 | |||
Fourth Quarter(1) | $ | 24.05 | $ | 7.12 | |||
(1) | Stock prices reflect the consummation of the Spin-off in the fourth quarter of 2015. |
On February 18, 2016, the closing price of our common stock was $4.31 per share. As of February 11, 2016, there were approximately 1,283 holders of record of our common stock.
We had not paid any cash dividends on our common stock since our formation through the year ended December 31, 2013. During 2015 and 2014, our board of directors declared and paid quarterly cash dividends of $0.15 per share of common stock to our stockholders. The following table sets forth dividends declared and paid during 2015 and 2014 per common share:
Declaration Date | Payment Date | Dividends per Common Share | Total Dividends | |||||||
February 25, 2014 | March 28, 2014 | $ | 0.15 | $ | 10.0 | million | ||||
April 29, 2014 | May 16, 2014 | 0.15 | 10.0 | million | ||||||
July 31, 2014 | August 18, 2014 | 0.15 | 10.0 | million | ||||||
October 30, 2014 | November 17, 2014 | 0.15 | 10.3 | million | ||||||
January 30, 2015 | February 17, 2015 | 0.15 | 10.3 | million | ||||||
April 28, 2015 | May 18, 2015 | 0.15 | 10.4 | million | ||||||
July 30, 2015 | August 18, 2015 | 0.15 | 10.5 | million | ||||||
October 18, 2015 | October 30, 2015 | 0.15 | 10.4 | million | ||||||
On January 26, 2016, our board of directors declared a quarterly dividend of $0.1875 per share of common stock which was paid on February 16, 2016 to stockholders of record at the close of business on February 9, 2016. Any future determinations to pay cash dividends to our stockholders will be at the discretion of our board of directors and will be dependent upon our financial condition and results of operations, credit and loan agreements in effect at that time and other factors deemed relevant by our board of directors.
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 Annual Report on Form 10-K.
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The performance graph below shows the cumulative total stockholder return on our common stock, compared with the S&P 500 Composite Stock Price Index (the “S&P 500 Index”) and the Oilfield Service Index (the “OSX”) over the five-year period beginning on December 31, 2009. The results are based on an investment of $100 in each of our common stock, the S&P 500 Index and the OSX. The graph assumes the reinvestment of dividends and adjusts all closing prices and dividends for stock splits.
Comparison of Five Year Cumulative Total Return
The performance graph shall not be deemed incorporated by reference by any general statement incorporating by reference this Annual Report on Form 10-K into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that we specifically incorporate this information by reference, and shall not otherwise be deemed filed under those Acts.
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Unregistered Sales of Equity Securities and Use of Proceeds
None.
Repurchase of Equity Securities
The following table summarizes our repurchases of equity securities during the three months ended December 31, 2015:
Period | Total Number of Shares Repurchased (1) | Average Price Paid Per Unit | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Maximum Number of Shares yet to be Purchased Under the Publicly Announced Plans or Programs | |||||||
October 1, 2015- October 31, 2015 | — | $ | — | N/A | N/A | ||||||
November 1, 2015 - November 30, 2015 | 14,767 | 12.62 | N/A | N/A | |||||||
December 1, 2015 - December 31, 2015 | 3,519 | 7.82 | N/A | N/A | |||||||
Total | 18,286 | $ | 11.70 | N/A | N/A | ||||||
(1) | Represents shares withheld to satisfy employees’ tax withholding obligations in connection with vesting of restricted stock awards during the period. |
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Item 6. Selected Financial Data
The table below shows certain selected financial data for Archrock for each of the five years in the period ended December 31, 2015, which has been derived from our audited Financial Statements. As discussed in Note 2 (“Discontinued Operations”) to our Financial Statements, the results from continuing operations for all periods presented exclude the results of the Spin-off of Exterran Corporation and the contract water treatment business. Those results are reflected in discontinued operations for all periods presented. 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 this Annual Report on Form 10-K (in thousands, except per share data):
Years Ended December 31, | |||||||||||||||||||
2015 | 2014 | 2013 | 2012 | 2011 | |||||||||||||||
Statement of Operations Data: | |||||||||||||||||||
Revenues | $ | 998,108 | $ | 959,153 | $ | 862,772 | $ | 836,824 | $ | 779,856 | |||||||||
Gross margin(1) | 503,062 | 454,760 | 391,794 | 355,804 | 304,535 | ||||||||||||||
Selling, general and administrative | 131,919 | 132,651 | 118,851 | 127,900 | 107,136 | ||||||||||||||
Depreciation and amortization | 229,127 | 212,268 | 187,476 | 181,678 | 178,492 | ||||||||||||||
Long-lived asset impairment(2) | 124,979 | 42,828 | 16,696 | 131,417 | 5,716 | ||||||||||||||
Restructuring charges(3) | 4,745 | 5,394 | — | 2,579 | 4,463 | ||||||||||||||
Goodwill impairment(4) | 3,738 | — | — | — | 31,994 | ||||||||||||||
Interest expense | 107,617 | 112,273 | 112,194 | 129,058 | 145,100 | ||||||||||||||
Debt extinguishment costs | 9,201 | — | — | — | — | ||||||||||||||
Other (income) expense, net | (2,079 | ) | (5,475 | ) | (22,535 | ) | (5,132 | ) | (5,284 | ) | |||||||||
Provision for (benefit from) income taxes | 53,189 | (28,066 | ) | (17,840 | ) | (77,034 | ) | (50,379 | ) | ||||||||||
Loss from continuing operations | (159,374 | ) | (17,113 | ) | (3,048 | ) | (134,662 | ) | (112,703 | ) | |||||||||
Net income (loss) from discontinued operations, net of tax(5) | 60,408 | 142,995 | 158,790 | 97,493 | (226,915 | ) | |||||||||||||
Net income (loss) attributable to noncontrolling interest | 6,852 | 27,716 | 32,578 | 2,317 | 990 | ||||||||||||||
Net income (loss) attributable to Archrock stockholders | (105,818 | ) | 98,166 | 123,164 | (39,486 | ) | (340,608 | ) | |||||||||||
Loss from continuing operations attributable to Archrock stockholders per common share: | |||||||||||||||||||
Basic | $ | (2.44 | ) | $ | (0.68 | ) | $ | (0.55 | ) | $ | (2.16 | ) | $ | (1.82 | ) | ||||
Diluted | $ | (2.44 | ) | $ | (0.68 | ) | $ | (0.55 | ) | $ | (2.16 | ) | $ | (1.82 | ) | ||||
Weighted average common shares outstanding used in income (loss) per common share: | |||||||||||||||||||
Basic | 68,433 | 66,234 | 64,454 | 63,436 | 62,624 | ||||||||||||||
Diluted | 68,433 | 66,234 | 64,454 | 63,436 | 62,624 | ||||||||||||||
Other Financial Data: | |||||||||||||||||||
EBITDA, as adjusted(6) | $ | 373,222 | $ | 330,055 | $ | 295,724 | $ | 233,036 | $ | 202,683 | |||||||||
Capital expenditures: | |||||||||||||||||||
Contract Operations Equipment: | |||||||||||||||||||
Growth(7) | $ | 154,500 | $ | 291,781 | $ | 194,727 | $ | 153,890 | $ | 97,140 | |||||||||
Maintenance(8) | $ | 75,044 | 71,767 | 73,606 | 77,678 | 76,108 | |||||||||||||
Other | 26,598 | 20,293 | 23,197 | 32,373 | 16,355 | ||||||||||||||
Dividends declared and paid per common share | $ | 0.60 | $ | 0.60 | $ | — | $ | — | $ | — | |||||||||
Balance Sheet Data: | |||||||||||||||||||
Cash and cash equivalents | $ | 1,563 | $ | 378 | $ | 471 | $ | 434 | $ | 449 | |||||||||
Working capital(9) | 150,199 | 575,737 | 464,180 | 376,350 | 420,273 | ||||||||||||||
Property, plant and equipment, net | 2,267,788 | 2,372,081 | 1,855,076 | 1,807,691 | 1,901,026 | ||||||||||||||
Total assets | 2,706,763 | 4,926,839 | 4,244,007 | 4,294,010 | 4,434,214 | ||||||||||||||
Long-term debt | 1,588,465 | 2,025,795 | 1,500,616 | 1,564,923 | 1,772,899 | ||||||||||||||
Total Archrock stockholder’s equity | 733,910 | 1,797,260 | 1,662,090 | 1,478,613 | 1,437,236 | ||||||||||||||
(1) | Gross margin, a non-GAAP financial measure, is defined, reconciled to net income (loss) and discussed further below under “Non-GAAP Financial Measures.” |
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(2) | For a discussion of long-lived asset impairment, see Note 12 (“Long-Lived Asset Impairment”) to our Financial Statements. |
(3) | For a discussion of restructuring charges, see Note 13 (“Restructuring Charges”) to our Financial Statements. |
(4) | For a discussion of goodwill impairment, see Note 6 (“Goodwill”) to our Financial Statements. |
(5) | For a discussion of discontinued operations, see Note 2 (“Discontinued Operations”) to our Financial Statements. |
(6) | EBITDA, as adjusted, a non-GAAP financial measure, is defined, reconciled to net income (loss) and discussed further below under “Non-GAAP Financial Measures.” |
(7) | Growth capital expenditures are made to expand or to replace partially or fully depreciated assets or to expand the operating capacity or revenue of existing or new assets, whether through construction, acquisition or modification. The majority of our growth capital expenditures are related to the acquisition cost of new compressor units that we add to our fleet. In addition, growth capital expenditures can also include the upgrading of major components on an existing compressor unit where the current configuration of the compressor unit is no longer in demand and the compressor unit is not likely to return to an operating status without the capital expenditures. These latter expenditures substantially modify the operating parameters of the compressor unit such that it can be used in applications that it previously was not suited for. |
(8) | Maintenance capital expenditures are made to maintain the existing operating capacity of our assets and related cash flows further extending the useful lives of the assets. Maintenance capital expenditures are related to the major overhauls of significant components of a compressor unit, such as the engine, compressor and cooler, that return the components to a like new condition, but do not modify the applications that the compressor unit was designed for. |
(9) | Working capital is defined as current assets minus current liabilities. |
Non-GAAP Financial Measures
We define gross margin as total revenue less cost of sales (excluding depreciation and amortization expense). Gross margin is included as a supplemental disclosure because it is a primary measure used by our management to evaluate the results of revenue and cost of sales (excluding depreciation and amortization expense), which are key components of our operations. We believe gross margin is important because it focuses on the current operating performance of our operations and excludes the impact of the prior historical costs of the assets acquired or constructed that are utilized in those operations, the indirect costs associated with our selling, general and administrative activities (“SG&A”) activities, the impact of our financing methods and income taxes. Depreciation and amortization expense may not accurately reflect the costs required to maintain and replenish the operational usage of our assets and therefore may not portray the costs from current operating activity. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income (loss) as determined in accordance with accounting principles generally accepted in the U.S. (“GAAP”). Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.
Gross margin has certain material limitations associated with its use as compared to net income (loss). These limitations are primarily due to the exclusion of interest expense, depreciation and amortization expense, SG&A expense, impairments and restructuring charges. Each of these excluded expenses is material to our consolidated statements of operations. Because we intend to finance a portion of our operations through borrowings, interest expense is a necessary element of our costs and our ability to generate revenue. Additionally, because we use capital assets, depreciation expense is a necessary element of our costs and our ability to generate revenue, and SG&A expenses are necessary to support our operations and required corporate activities. To compensate for these limitations, management uses this non-GAAP measure as a supplemental measure to other GAAP results to provide a more complete understanding of our performance.
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The following table reconciles our net income (loss) to gross margin (in thousands):
Years Ended December 31, | |||||||||||||||||||
2015 | 2014 | 2013 | 2012 | 2011 | |||||||||||||||
Net income (loss) | $ | (98,966 | ) | $ | 125,882 | $ | 155,742 | $ | (37,169 | ) | $ | (339,618 | ) | ||||||
Selling, general and administrative | 131,919 | 132,651 | 118,851 | 127,900 | 107,136 | ||||||||||||||
Depreciation and amortization | 229,127 | 212,268 | 187,476 | 181,678 | 178,492 | ||||||||||||||
Long-lived asset impairment | 124,979 | 42,828 | 16,696 | 131,417 | 5,716 | ||||||||||||||
Restructuring charges | 4,745 | 5,394 | — | 2,579 | 4,463 | ||||||||||||||
Goodwill impairment | 3,738 | — | — | — | 31,994 | ||||||||||||||
Interest expense | 107,617 | 112,273 | 112,194 | 129,058 | 145,100 | ||||||||||||||
Debt extinguishment costs | 9,201 | — | — | — | — | ||||||||||||||
Other (income) expense, net | (2,079 | ) | (5,475 | ) | (22,535 | ) | (5,132 | ) | (5,284 | ) | |||||||||
Provision for (benefit from) income taxes | 53,189 | (28,066 | ) | (17,840 | ) | (77,034 | ) | (50,379 | ) | ||||||||||
(Income) loss from discontinued operations, net of tax | (60,408 | ) | (142,995 | ) | (158,790 | ) | (97,493 | ) | 226,915 | ||||||||||
Gross margin | $ | 503,062 | $ | 454,760 | $ | 391,794 | $ | 355,804 | $ | 304,535 | |||||||||
We define EBITDA, as adjusted, as net income (loss) excluding income (loss) from discontinued operations (net of tax), cumulative effect of accounting changes (net of tax), income taxes, interest expense (including debt extinguishment costs and gain or loss on termination of interest rate swaps), depreciation and amortization expense, impairment charges, restructuring charges, expensed acquisition costs and other items. We believe EBITDA, as adjusted, is an important measure of operating performance because it allows management, investors and others to evaluate and compare our core operating results from period to period by removing the impact of discontinued operations, our capital structure (interest expense from our outstanding debt), asset base (depreciation and amortization), tax consequences, impairment charges, restructuring charges, expensed acquisition costs and other items. Management uses EBITDA, as adjusted, as a supplemental measure to review current period operating performance, comparability measures and performance measures for period to period comparisons. Our EBITDA, as adjusted, may not be comparable to a similarly titled measure of another company because other entities may not calculate EBITDA in the same manner.
EBITDA, as adjusted, is not a measure of financial performance under GAAP, and should not be considered in isolation or as an alternative to net income (loss), cash flows from operating activities and other measures determined in accordance with GAAP. Items excluded from EBITDA, as adjusted, are significant and necessary components to the operations of our business, and, therefore, EBITDA, as adjusted, should only be used as a supplemental measure of our operating performance.
The following table reconciles our net income (loss) to EBITDA, as adjusted (in thousands):
Years Ended December 31, | |||||||||||||||||||
2015 | 2014 | 2013 | 2012 | 2011 | |||||||||||||||
Net income (loss) | $ | (98,966 | ) | $ | 125,882 | $ | 155,742 | $ | (37,169 | ) | $ | (339,618 | ) | ||||||
(Income) loss from discontinued operations, net of tax | (60,408 | ) | (142,995 | ) | (158,790 | ) | (97,493 | ) | 226,915 | ||||||||||
Depreciation and amortization | 229,127 | 212,268 | 187,476 | 181,678 | 178,492 | ||||||||||||||
Long-lived asset impairment | 124,979 | 42,828 | 16,696 | 131,417 | 5,716 | ||||||||||||||
Restructuring charges | 4,745 | 5,394 | — | 2,579 | 4,463 | ||||||||||||||
Goodwill impairment | 3,738 | — | — | — | 31,994 | ||||||||||||||
Debt extinguishment costs | 9,201 | — | — | — | — | ||||||||||||||
Interest expense | 107,617 | 112,273 | 112,194 | 129,058 | 145,100 | ||||||||||||||
Expensed acquisition costs | — | 2,471 | 246 | — | — | ||||||||||||||
Provision for (benefit from) income taxes | 53,189 | (28,066 | ) | (17,840 | ) | (77,034 | ) | (50,379 | ) | ||||||||||
EBITDA, as adjusted | $ | 373,222 | $ | 330,055 | $ | 295,724 | $ | 233,036 | $ | 202,683 | |||||||||
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our Financial Statements, the notes thereto, and the other financial information appearing elsewhere in this Annual Report on Form 10-K. 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 Annual Report on Form 10-K.
Overview
We are a pure play U.S. natural gas contract operations services business and the leading provider of natural gas compression services to customers in the oil and natural gas industry throughout the U.S. and a leading supplier of aftermarket services to customers that own compression equipment in the U.S. Our services are essential to the production, processing, transportation and storage of natural gas and are provided primarily to producers and distributors of oil and natural gas. Our geographic business unit operating structure, technically experienced personnel and large fleet of natural gas compression equipment enable us to provide reliable contract operations services to our customers throughout the U.S.
Our revenues and income are derived from two primary business segments:
• | Contract Operations. As of December 31, 2015, our contract operations business was largely comprised of our significant equity investment in Archrock Partners, L.P. and its subsidiaries, in addition to our owned fleet of natural gas compression equipment that we use to provide operations services to our customers. |
• | Aftermarket Services. Our aftermarket services business provides a full range of services to support the compression needs of customers. We sell parts and components and provide operations, maintenance, overhaul and reconfiguration services to customers who own compression equipment. |
Archrock Partners, L.P.
We have a significant equity interest in the Partnership, a master limited partnership that provides natural gas contract operations services to customers throughout the U.S. As of December 31, 2015, public unitholders held a 59% ownership interest in the Partnership and we owned the remaining equity interest, including all of the general partner interest and incentive distribution rights. We consolidate the financial position and results of operations of the Partnership. It is our intention for the Partnership to be the primary vehicle for the growth of our contract operations business and we may grow the Partnership through third-party acquisitions, organic growth and the future transfer by us of additional contract operations customer contracts and equipment to the Partnership in exchange for cash, the Partnership’s assumption of our debt and/or additional equity interests in the Partnership. As of December 31, 2015, the Partnership’s fleet included 6,494 compressor units comprising approximately 3.3 million horsepower, or 83% of our and the Partnership’s combined total U.S. horsepower.
On April 17, 2015, at the closing of the April 2015 Contract Operations Acquisition, we sold to the Partnership contract operations customer service agreements with 60 customers and a fleet of 238 compressor units used to provide compression services under those agreements, comprising approximately 148,000 horsepower, or 3% (of then available horsepower) of the combined contract operations business of the Partnership and us. The assets sold to the Partnership also included 179 compressor units, comprising approximately 66,000 horsepower, previously leased by us to the Partnership. Total consideration for the transaction was approximately $102.3 million, excluding transaction costs, and consisted of the Partnership’s issuance to us of approximately 4.0 million common units and approximately 80,000 general partner units. Based on the terms of the contribution, conveyance and assumption agreement relating to the acquisition, the common units and general partner units, including incentive distribution rights, we received in this transaction were not entitled to receive a cash distribution relating to the quarter ended March 31, 2015. We refer to this acquisition as the “April 2015 Contract Operations Acquisition.”
On August 8, 2014, the Partnership completed an acquisition of natural gas compression assets, including a fleet of 162 compressor units, comprising approximately 110,000 horsepower from MidCon Compression, L.L.C. (“MidCon”) for $130.1 million. The majority of the horsepower acquired is utilized under a five-year contract operations services agreement with BHP Billiton Petroleum (“BHP Billiton”), which expires in March 2019, to provide compression services. In accordance with the terms of the purchase and sale agreement relating to this acquisition, the Partnership directed MidCon to sell a tract of real property and the facility located thereon, a fleet of vehicles, personal property and parts inventory to one of our wholly-owned subsidiaries, for $4.1 million. These assets are used in conjunction with the compression units the Partnership acquired from MidCon to provide compression services. We refer to the acquisition of these assets by the Partnership and our wholly-owned subsidiary as the “August 2014 MidCon Acquisition.”
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On April 10, 2014, the Partnership completed an acquisition of natural gas compression assets, including a fleet of 337 compressor units, comprising approximately 444,000 horsepower from MidCon for $352.9 million. The compressor units were previously used by MidCon to provide compression services to a subsidiary of Access Midstream Partners L.P. (“Access”). Effective as of the closing of the acquisition, the Partnership and Access entered into a seven-year contract operations services agreement under which the Partnership provides compression services to Access which, following its February 2015 merger with Williams Partners L.P., was renamed Williams Partners L.P. (“Williams Partners”). In accordance with the terms of the purchase and sale agreement relating to this acquisition, the Partnership directed MidCon to sell a tract of real property and the facility located thereon, a fleet of vehicles, personal property and parts inventory to one of our wholly-owned subsidiaries for $7.7 million. These assets are used in conjunction with the compression units the Partnership acquired from MidCon to provide compression services. We refer to the acquisition of these assets by the Partnership and our wholly-owned subsidiary as the “April 2014 MidCon Acquisition.”
Spin-off Transaction
On November 3, 2015 (the “Distribution Date”), we completed the spin-off (the “Spin-off”) of our international contract operations, international aftermarket services and global fabrication businesses into a standalone public company operating as Exterran Corporation. To effect the Spin-off, we distributed on the Distribution Date, on a pro rata basis, all of the shares of Exterran Corporation common stock to our stockholders as of October 27, 2015 (the “Record Date”). Archrock stockholders received one share of Exterran Corporation common stock for every two shares of our common stock held at the close of business on the Record Date. Upon the completion of the Spin-off, we were renamed “Archrock, Inc.” and, on November 4, 2015, the ticker symbol for our common stock on the New York Stock Exchange was changed to “AROC.” Following the completion of the Spin-off, we and Exterran Corporation are independent, publicly traded companies with separate public ownership, board of directors and management, and we continue to own and operate the U.S. contract operations and aftermarket services businesses that we previously owned. Additionally, we continue to hold our interests in the Partnership. Effective on November 3, 2015, the Partnership was renamed “Archrock Partners, L.P.,” and, on November 4, 2015, the ticker symbol for its common units on the Nasdaq Global Select Market was changed to “APLP.”
In order to effect the Spin-off and govern our relationship with Exterran Corporation after the Spin-off, we entered into several agreements with Exterran Corporation on November 3, 2015:
• | Separation and Distribution Agreement. Our separation and distribution agreement with Exterran Corporation contains the key provisions relating to the separation of our business from Exterran Corporation’s business. The separation and distribution agreement identifies the assets and rights that were transferred, liabilities that were assumed or retained and contracts and related matters that were assigned to us or Exterran Corporation in the Spin-off and describes how these transfers, assumptions and assignments occurred. In addition, the separation and distribution agreement contains certain noncompetition provisions addressing restrictions for three years after the Spin-off on Exterran Corporation’s ability to provide contract operations and aftermarket services in the United States and on our ability to provide contract operations and aftermarket services outside of the United States and to provide products for sale worldwide that compete with Exterran Corporation’s product sales business, subject to certain exceptions. Additionally, the separation and distribution agreement specifies our right to receive payments from a subsidiary of Exterran Corporation based on a notional amount corresponding to payments received by Exterran Corporation’s subsidiaries from PDVSA Gas, a subsidiary of Petroleos de Venezuela, S.A. (“PDVSA”), in respect of the sale of Exterran Corporation’s subsidiaries’ and joint ventures’ previously nationalized assets. |
• | Tax Matters Agreement. Our tax matters agreement with Exterran Corporation governs the respective rights, responsibilities and obligations of Exterran Corporation and us with respect to tax liabilities and benefits, tax attributes, the preparation and filing of tax returns, the control of audits and other tax proceedings and certain other matters regarding taxes. |
• | Employee Matters Agreement. Our employee matters agreement with Exterran Corporation governs the allocation of liabilities and responsibilities between us and Exterran Corporation relating to employee compensation and benefit plans and programs, including the treatment of retirement, health and welfare plans and equity and other incentive plans and awards. |
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• | Transition Services Agreement. Our transition services agreement with Exterran Corporation sets forth the terms on which Exterran Corporation will provide to us, and we will provide to Exterran Corporation, on a temporary basis, certain services or functions that the companies historically have shared, including accounting, administrative, payroll, human resources, environmental health and safety, real estate, fleet, financial audit support, legal, tax, treasury and other support and corporate services. |
• | Supply Agreement. Our supply agreement with Exterran Corporation sets forth the terms under which Exterran Corporation will provide manufactured equipment, including the design, engineering, manufacturing and sale of natural gas compression equipment, on an exclusive basis to us and the Partnership. |
• | Storage Agreement. Our storage agreements with Exterran Corporation set forth the terms under which Exterran Corporation will provide each of us and the Partnership with storage space for equipment purchased under the supply agreement, as well as the terms under which we will provide storage space to Exterran Corporation for certain of its equipment. |
• | Services Agreements. Our services agreements with Exterran Corporation set forth the terms under which Exterran Corporation will provide us (or our customers on our behalf) with engineering, preservation and installation and commissioning services and we will provide Exterran Corporation (or its customers on its behalf) with make-ready, parts sales, preservation and installation and commissioning services. |
Exterran Corporation’s capital structure includes a new $925.0 million credit facility, consisting of a $680.0 million revolving credit facility and a $245.0 million term loan facility (collectively, the “Exterran Corporation Credit Facility”) that became available on November 3, 2015. Exterran Corporation transferred the net proceeds from the borrowings under the Exterran Corporation Credit Facility to us to allow for our repayment of a portion of our indebtedness prior to the Spin-off. Our capital structure includes a new $350.0 million revolving credit facility that became available on November 3, 2015.
Results of operations for Exterran Corporation have been classified as discontinued operations in all periods presented in this Annual Report on Form 10-K. For additional information, see Note 2 (“Discontinued Operations”) to our Financial Statements within Part IV, Item 15 “Exhibits and Financial Statement Schedules” in this Annual Report on Form 10-K.
Trends and Outlook
Our business environment and corresponding operating results are affected by the level of energy industry spending for the exploration, development and production of oil and natural gas reserves in the U.S. Spending by oil and natural gas exploration and production companies is dependent upon these companies’ forecasts regarding the expected future supply, demand and pricing of oil and natural gas products as well as their estimates of risk-adjusted costs to find, develop and produce reserves. Oil and natural gas prices and the level of drilling and exploration activity can be volatile. For example, oil and natural gas exploration and development activity and the number of well completions typically decline when there is a significant reduction in oil and natural gas prices or significant instability in energy markets. Our revenue, earnings and financial position are affected by, among other things, market conditions that impact demand and pricing for natural gas compression, our customers’ decisions between using our services or our competitors’ services, our customers’ decisions regarding whether to own and operate the equipment themselves and the timing and consummation of any acquisition of additional contract operations customer service agreements and equipment from third parties. Although we believe our business is typically less impacted by commodity prices than certain other oil and natural gas service providers, changes in oil and natural gas exploration and production spending normally result in changes in demand for our services.
Natural gas consumption in the U.S. for the twelve months ended November 30, 2015 increased by approximately 2% to approximately 27,551 Bcf compared to approximately 26,931 Bcf for the twelve months ended November 30, 2014. The U.S. Energy Information Administration (“EIA”) forecasts that total U.S. natural gas consumption will increase by 1.5% in 2016 compared to 2015. The EIA estimates that the U.S. natural gas consumption level will be approximately 30 Tcf in 2040, or 16% of the projected worldwide total of approximately 185 Tcf.
Natural gas marketed production in the U.S. for the twelve months ended November 30, 2015 increased by approximately 6% to 28,849 Bcf compared to 27,096 Bcf for the twelve months ended November 30, 2014. The EIA forecasts that total U.S. natural gas marketed production will increase by 0.7% in 2016 compared to 2015. The EIA estimates that the U.S. natural gas production level will be approximately 33 Tcf in 2040, or 18% of the projected worldwide total of approximately 187 Tcf.
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Historically, oil and natural gas prices in the U.S. have been volatile. For example, the Henry Hub spot price for natural gas was $2.28 per MMBtu at December 31, 2015, which was approximately 8% and 27% lower than prices at September 30, 2015 and December 31, 2014, respectively, and the U.S. natural gas liquid composite price was $4.72 per MMBtu for the month of November 2015, which was approximately 3% and 16% lower than the price for the months of September 2015 and December 2014, respectively. These price declines have caused many companies to reduce their natural gas drilling and production activities, particularly in more mature and predominantly dry gas areas and shale plays in the U.S., where we provide a significant amount of contract operations services, which led to a decline in our contract operations business during 2015. These price declines are expected to lead to a continued decrease in capital investment and in the number of new gas wells being drilled in 2016 by exploration and production companies. In addition, the West Texas Intermediate crude oil spot price was $37.13 per barrel at December 31, 2015 which was approximately 18% and 31% lower than prices at September 30, 2015 and December 31, 2014, respectively, which is expected to lead to a continued decrease in capital investment and in the number of new oil wells being drilled in 2016 by exploration and production companies. Because we provide a significant amount of contract operations services related to the production of associated gas from oil wells and the use of gas lift to enhance production of oil from oil wells, our operations and our levels of operating horsepower are also impacted by crude oil drilling and production activity.
During periods of lower oil or natural gas prices, our customers may not be able to recover the full amount of their drilling and production costs in the regions in which we operate. As a result, our customers may cease production in existing wells and decline to drill new wells, which would lower their demand for our services. Additionally, some of our midstream customers may provide their gathering, transportation and related services to a limited number of companies in the oil and gas production business. The loss by these midstream customers of their key customers could reduce demand for their services and result in a deterioration of their financial condition, which would in turn decrease their demand for our services. A reduction in the demand for our services could result in our customers seeking to preserve capital by canceling contracts, canceling or delaying scheduled maintenance of their existing equipment or determining not to enter into new contract operations service contracts, which could force us to reduce our pricing substantially. As a result of the significant decline in oil and natural gas prices since the third quarter of 2014, U.S. producers reduced their capital budgets for 2015 and research analysts are forecasting declines in U.S. capital spending for drilling activity in 2016. In 2015, we experienced an operating horsepower decline. Due to the expected continued decrease in customer spending in 2016 and the expectation that customers will cease production from wells that are uneconomic for them to produce, we anticipate lower demand for our services during 2016 than in 2015. As a result, we expect continued operating horsepower declines in 2016 and we may also experience increased pricing pressure on the services we provide during 2016, which is expected to result in a decline in our contract operations business in 2016. We also anticipate investing less capital in new fleet units in 2016 than we did in 2015.
We may contribute additional contract operations customer contracts and equipment to the Partnership in the future in exchange for cash, the Partnership’s assumption of our debt and/or our receipt of additional interests in the Partnership. Any such transaction depends on, among other things, market and economic conditions, our ability to agree with the Partnership regarding the terms of any purchase and the availability to the Partnership of debt and equity capital on reasonable terms.
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Certain Key Challenges and Uncertainties
Market conditions in the oil and natural gas industry and competition in the natural gas compression industry continue to represent key challenges and uncertainties. In addition to these challenges, we believe the following represent some of the key challenges and uncertainties we will face in the near future:
U.S. Market and Oil and Natural Gas Pricing.
Historically, oil and natural gas prices in the U.S. have been volatile, and they have declined significantly since the third quarter of 2014. As a result of this significant decline in oil and natural gas prices, U.S. producers reduced their capital budgets for 2015 and research analysts are forecasting declines in U.S. capital spending for drilling activity in 2016. During periods of lower oil or natural gas prices, our customers may not be able to recover the full amount of their drilling and production costs in the regions in which we operate. As a result, our customers may cease production in existing wells and decline to drill new wells, which would lower their demand for our services. Additionally, some of our midstream customers may provide their gathering, transportation and related services to a limited number of companies in the oil and gas production business. The loss by these midstream customers of their key customers could reduce demand for their services and result in a deterioration of their financial condition, which would in turn decrease their demand for our services. A reduction in the demand for our services could result in our customers seeking to preserve capital by canceling contracts, canceling or delaying scheduled maintenance of their existing equipment or determining not to enter into new contract operations service contracts, which could lead to a reduction in our business activity levels and our pricing. Many of our contracts with customers have short initial terms and are typically cancelable on short notice after the initial term, and we cannot be certain that these contracts will be extended or renewed after the end of the initial contractual term. In 2015, we experienced an operating horsepower decline. Due to the expected continued decrease in customer spending in 2016, we anticipate lower demand for our services during 2016 than in 2015. As a result, we expect continued operating horsepower declines in 2016 and we may also experience increased pricing pressure on the services we provide during 2016, which is expected to result in a decline in our contract operations business in 2016.
In addition, during times when the oil or natural gas markets weaken, our customers are more likely to experience a downturn in their financial condition. In the event of the financial failure of a customer, we could experience a loss on all or a portion of our outstanding accounts receivable associated with that customer.
Dependence on the Partnership. To generate the funds necessary to meet our obligations, fund our business and pay dividends, we depend heavily on the cash flows and distributions attributable to our ownership interest in the Partnership. Our ownership interest in the Partnership, including our limited partner interest, general partner interest and incentive distribution rights in the Partnership, is currently our largest cash-generating asset. As a result, our cash flow is heavily dependent upon the ability of the Partnership to make distributions to its partners. Due to the expected continued decrease in customer spending in 2016 and the expectation that customers will cease production from wells that are uneconomic for them to continue to produce, we anticipate lower demand for the Partnership’s contract operations services during 2016 than in 2015. As a result, we expect the Partnership to experience operating horsepower declines in 2016 and it may also experience increased pricing pressure on the services it provides during 2016, which is expected to result in a decline in the Partnership’s contract operations business in 2016. A decline in the Partnership’s business or revenues or increases in its expenses, principal and interest payments under existing and future debt instruments, working capital requirements or other cash needs could limit the amount of cash the Partnership has available to distribute to its unit holders, including us. A reduction in the amount of cash distributions we receive from the Partnership would reduce the amount of cash available to us for the payment of dividends, the payment of our debt and the funding of our business requirements.
Availability of External Sources of Capital. We may not be able to maintain or grow our asset and customer base unless we have access to sufficient capital to purchase additional compression equipment. Historically, we have financed acquisitions, operating expenditures and capital expenditures with a combination of cash provided by operating and financing activities. However, to the extent we are unable to finance our operating expenditures, capital expenditures, scheduled interest and debt repayments and any future dividends with net cash provided by operating activities and borrowings under our credit facility, we may require additional capital. Recent instability in the capital markets (both generally and in the oil and gas industry in particular) could limit our ability to access the capital markets to raise debt or equity capital on affordable terms or to obtain additional financing. If we are not successful in raising capital within the time period required or at all, we may not be able to grow or maintain our business.
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Cost Management. In January 2016, we determined to undertake a cost reduction program to reduce our on-going operating expenses in light of current and expected activity levels. This cost reduction program is intended to help mitigate the impact of the anticipated overall decline in our contract operations business during 2016 as a result of the low commodity price environment. However, achieving significant cost reductions will be challenging, and there is no guarantee that our cost reduction program will result in a reduction in our operating expenses or offset any declines in revenue.
Personnel, Hiring, Training and Retention. We believe that our ability to hire, train and retain qualified personnel will continue to be important. Although we have been able to satisfy our personnel needs thus far, retaining employees in our industry continues to be a challenge. Additionally, following the closing of the Spin-off, certain of our key personnel became employees of Exterran Corporation. Our ability to grow and to continue our current level of service to our customers will depend in part on our success in hiring, training and retaining our employees.
Summary of Results
As discussed in Note 2 (“Discontinued Operations”) to our Financial Statements, the results from continuing operations for all periods presented exclude the results of Exterran Corporation and our contract water treatment business. Those results are reflected in discontinued operations for all periods presented.
Net Income (loss) attributable to Archrock stockholders. We generated net loss attributable to Archrock stockholders of $105.8 million during the year ended December 31, 2015 and net income attributable to Archrock Stockholders of $98.2 million and $123.2 million during the years ended December 31, 2014 and 2013, respectively. The net loss attributable to Archrock stockholders during the year ended December 31, 2015 compared to the net income attributable to Archrock stockholders during the year ended December 31, 2014 was primarily due to an increase in income tax expense driven by a valuation allowance taken against foreign tax credits allocated to Exterran Corporation, an increase in long-lived asset impairment, a decrease in income from discontinued operations, net, and an increase in depreciation and amortization expense. These activities were partially offset by an increase in gross margin in our contract operations segment and a decrease in net income attributable to the noncontrolling interest. The decrease in net income attributable to Archrock stockholders during the year ended December 31, 2014 compared to the year ended December 31, 2013 was primarily due to an increase in long-lived asset impairment, an increase in depreciation and amortization expense, an $18.4 million decrease in gain on sale of property, plant and equipment, a decrease in income from discontinued operations, net, an increase in SG&A expense and an increase in restructuring and other charges. These activities were partially offset by an increase in gross margin in our contract operations segment and an increase in benefit from income taxes.
EBITDA, as adjusted. We define EBITDA, as adjusted, as net income (loss) excluding income (loss) from discontinued operations (net of tax), cumulative effect of accounting changes (net of tax), income taxes, interest expense (including debt extinguishment costs and gain or loss on termination of interest rate swaps), depreciation and amortization expense, impairment charges, restructuring charges, expensed acquisition costs and other items. We believe EBITDA, as adjusted, is an important measure of operating performance because it allows management, investors and others to evaluate and compare our core operating results from period to period by removing the impact of discontinued operations, our capital structure (interest expense from our outstanding debt), asset base (depreciation and amortization), tax consequences, impairment charges, restructuring charges, expensed acquisition costs and other items. Management uses EBITDA, as adjusted, as a supplemental measure to review current period operating performance, comparability measures and performance measures for period to period comparisons. Our EBITDA, as adjusted, may not be comparable to a similarly titled measure of another company because other entities may not calculate EBITDA in the same manner.
EBITDA, as adjusted, is not a measure of financial performance under GAAP, and should not be considered in isolation or as an alternative to net income (loss), cash flows from operating activities and other measure determined in accordance with GAAP. Items excluded from EBITDA, as adjusted, are significant and necessary components to the operations of our business, and, therefore, EBITDA, as adjusted, should only be used as a supplemental measure of our operating performance.
Our EBITDA, as adjusted, was $373.2 million, $330.1 million and $295.7 million during the years ended December 31, 2015, 2014 and 2013, respectively. EBITDA, as adjusted, during the year ended December 31, 2015 compared to the year ended December 31, 2014 increased primarily due to higher gross margin in our contract operations segment, partially offset by a $4.0 million decrease in gain on sale of property, plant and equipment. EBITDA, as adjusted, during the year ended December 31, 2014 compared to the year ended December 31, 2013 increased primarily due to higher gross margin in our contract operations segment, partially offset by an $18.4 million decrease in gain on sale of property, plant and equipment and an increase in SG&A expense. For a reconciliation of EBITDA, as adjusted, to net income (loss), its most directly comparable financial measure calculated and presented in accordance with GAAP, please read Part II, Item 6 (“Selected Financial Data — Non-GAAP Financial Measures”) of this Annual Report on Form 10-K.
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Results by Business Segment. The following table summarizes revenue, gross margin and gross margin percentages for each of our business segments (dollars in thousands):
Years Ended December 31, | |||||||||||
2015 | 2014 | 2013 | |||||||||
Revenue: | |||||||||||
Contract Operations | $ | 781,166 | $ | 729,103 | $ | 627,844 | |||||
Aftermarket Services | 216,942 | 230,050 | 234,928 | ||||||||
$ | 998,108 | $ | 959,153 | $ | 862,772 | ||||||
Gross Margin (1): | |||||||||||
Contract Operations | $ | 461,765 | $ | 412,961 | $ | 345,355 | |||||
Aftermarket Services | 41,297 | 41,799 | 46,439 | ||||||||
$ | 503,062 | $ | 454,760 | $ | 391,794 | ||||||
Gross Margin percentage (2): | |||||||||||
Contract Operations | 59 | % | 57 | % | 55 | % | |||||
Aftermarket Services | 19 | % | 18 | % | 20 | % | |||||
(1) | Defined as revenue less cost of sales, excluding depreciation and amortization expense. Gross margin, a non-GAAP financial measure, is reconciled, in total, to net income (loss), its most directly comparable financial measure calculated and presented in accordance with GAAP in Part II, Item 6 (“Selected Financial Data — Non-GAAP Financial Measures”) of this Annual Report on Form 10-K. |
(2) | Defined as gross margin divided by revenue. |
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Operating Highlights
The following tables summarize our total available horsepower, total operating horsepower, average operating horsepower and horsepower utilization percentages (in thousands, except percentages):
Years Ended December 31, | ||||||||
2015 | 2014 | 2013 | ||||||
Total Available Horsepower (at period end): | 4,011 | 4,209 | 3,429 | |||||
Total Operating Horsepower (at period end): | 3,493 | 3,700 | 2,884 | |||||
Average Operating Horsepower: | 3,620 | 3,346 | 2,871 | |||||
Horsepower Utilization (at period end): | 87 | % | 88 | % | 84 | % | ||
The Year ended December 31, 2015 Compared to the Year ended December 31, 2014
Contract Operations
(dollars in thousands)
Years Ended December 31, | Increase (Decrease) | |||||||||
2015 | 2014 | |||||||||
Revenue | $ | 781,166 | $ | 729,103 | 7 | % | ||||
Cost of sales (excluding depreciation and amortization expense) | 319,401 | 316,142 | 1 | % | ||||||
Gross margin | $ | 461,765 | $ | 412,961 | 12 | % | ||||
Gross margin percentage | 59 | % | 57 | % | 2 | % | ||||
The increase in revenue during the year ended December 31, 2015 compared to the year ended December 31, 2014 was primarily attributable to an 8% increase in average operating horsepower, which included the assets acquired in the August 2014 MidCon Acquisition and the April 2014 MidCon Acquisition. Gross margin (defined as revenue less cost of sales, excluding depreciation and amortization expense) and gross margin percentage increased during the year ended December 31, 2015 compared to the year ended December 31, 2014 primarily due to the increase in revenue attributable to the increase in average operating horsepower explained above and a decrease of $9.7 million in lube oil expenses resulting from a decrease in commodity prices and efficiency gains in lube oil consumption in the current year, offset by an increase in cost of sales attributable to the increase in average operating horsepower. Gross margin, a non-GAAP financial measure, is reconciled, in total, to net income (loss), its most directly comparable financial measure calculated and presented in accordance with GAAP, in Part II, Item 6 Selected Financial Data — Non GAAP Financial Measures to this Annual Report on Form 10-K.
Aftermarket Services
(dollars in thousands)
Years Ended December 31, | Increase (Decrease) | |||||||||
2015 | 2014 | |||||||||
Revenue | $ | 216,942 | $ | 230,050 | (6 | )% | ||||
Cost of sales (excluding depreciation and amortization expense) | 175,645 | 188,251 | (7 | )% | ||||||
Gross margin | $ | 41,297 | $ | 41,799 | (1 | )% | ||||
Gross margin percentage | 19 | % | 18 | % | 1 | % | ||||
The decrease in revenue during the year ended December 31, 2015 compared to the year ended December 31, 2014 was due to a decrease in service activities. Gross margin and gross margin percentage remained relatively flat during the year ended December 31, 2015 compared to the year ended December 31, 2014.
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Costs and Expenses
(dollars in thousands)
Years Ended December 31, | Increase (Decrease) | |||||||||
2015 | 2014 | |||||||||
Selling, general and administrative | $ | 131,919 | $ | 132,651 | (1 | )% | ||||
Depreciation and amortization | 229,127 | 212,268 | 8 | % | ||||||
Long-lived asset impairment | 124,979 | 42,828 | 192 | % | ||||||
Restructuring charges | 4,745 | 5,394 | (12 | )% | ||||||
Goodwill impairment | 3,738 | — | — | % | ||||||
Interest expense | 107,617 | 112,273 | (4 | )% | ||||||
Debt extinguishment costs | 9,201 | — | — | % | ||||||
Other (income) expense, net | (2,079 | ) | (5,475 | ) | (62 | )% | ||||
SG&A expense during the year ended December 31, 2015 compared to the year ended December 31, 2014 remained relatively flat. SG&A as a percentage of revenue was 13% and 14% during the years ended December 31, 2015 and 2014, respectively.
Depreciation and amortization expense during the year ended December 31, 2015 compared to the year ended December 31, 2014 increased primarily due to an increase in property, plant and equipment and intangible assets additions, including the assets acquired in the August 2014 MidCon Acquisition and the April 2014 MidCon Acquisition.
During the year ended December 31, 2015, we reviewed the future deployment of our idle compression assets used in our contract operations segment for units that were not of the type, configuration, condition, make or model that are cost efficient to maintain and operate. Based on this review, we determined that approximately 900 idle compressor units totaling approximately 371,000 horsepower would be retired from the active fleet during the year ended December 31, 2015. The retirement of these units from the active fleet triggered a review of these assets for impairment. As a result, we recorded a $111.7 million asset impairment to reduce the book value of each unit to its estimated fair value during the year ended December 31, 2015. The fair value of each unit was estimated based on either the expected net sale proceeds compared to other fleet units we recently sold and/or a review of other units recently offered for sale by third parties, or the estimated component value of the equipment we plan to use.
In connection with our fleet review during the year ended December 31, 2015, we evaluated for impairment idle units that had been culled from our fleet in prior years and were available for sale. Based upon that review, we reduced the expected proceeds from disposition for certain of the remaining units. This resulted in an additional impairment of $13.3 million during the year ended December 31, 2015 to reduce the book value of each unit to its estimated fair value.
During the year ended December 31, 2014, we evaluated the future deployment of our idle fleet and determined to retire and either sell or re-utilize the key components of approximately 290 idle compressor units, representing approximately 112,000 horsepower, previously used to provide services in our contract operations segment. As a result, we performed an impairment review and recorded a $30.4 million asset impairment to reduce the book value of each unit to its estimated fair value. The fair value of each unit was estimated based on either the expected net sale proceeds compared to other fleet units we recently sold and/or a review of other units recently offered for sale by third parties, or the estimated component value of the equipment we plan to use.
In connection with our fleet review during 2014, we evaluated for impairment idle units that had been culled from our fleet in prior years and were available for sale. Based upon that review, we reduced the expected proceeds from disposition for certain of the remaining units. This resulted in an additional impairment of $11.7 million to reduce the book value of each unit to its estimated fair value.
During the year ended December 31, 2014, we evaluated other long-lived assets for impairment and recorded long-lived asset impairments of $0.7 million on these assets.
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As discussed in Note 2 (“Discontinued Operations”) to our Financial Statements, we completed the Spin-off of Exterran Corporation on November 3, 2015. During the year ended December 31, 2015, we incurred $4.1 million of costs which were directly attributable to Archrock including retention and severance benefits and a non-cash inventory write-down. Non-cash inventory write-downs, which primarily related to the decentralization of shared inventory components between our contract operations business and the international contract operations business of Exterran Corporation, totaled $1.0 million. The costs related to the Spin-off have not been allocated to the segments because they primarily represent professional service fees within the corporate, finance and legal functions.
In the second quarter of 2015 we announced a cost reduction plan primarily focused on workforce reductions. During the year ended December 31, 2015, we incurred $0.6 million of restructuring and other charges as a result of this plan primarily related to termination benefits. These charges are reflected as restructuring and other charges in our consolidated statement of operations.
In January 2014, we announced a plan to centralize our make-ready operations to improve the cost and efficiency of our shops and further enhance the competitiveness of our fleet of compressors. As part of this plan, we examined both recent and anticipated changes in the U.S. market, including the throughput demand of our shops and the addition of new equipment to our fleet. To better align our costs and capabilities with the current market, we determined to close several of our make-ready shops. The centralization of our make-ready operations was completed in the second quarter of 2014. During the year ended December 31, 2014, we incurred $5.4 million of restructuring charges primarily related to termination benefits and a non-cash write-down of inventory associated with the centralization of our make-ready operations. See Note 13 (“Restructuring Charges”) to our Financial Statements for further discussion of these charges.
Beginning in late 2014 and extending throughout 2015, the energy markets experienced a significant reduction in oil and natural gas prices which has had a significant impact on the financial performance and operating results of many oil and natural gas companies. Such declines accelerated in the fourth quarter of 2015, resulting in higher borrowing costs for companies and a substantial reduction in forecasted capital spending across the energy industry leading to lower projected growth rates over the short-term. Such declines impacted our future cash flow forecasts, our market capitalization, and the market capitalization of peer companies. We identified these conditions as a triggering event, which required us to perform a goodwill impairment test as of December 31, 2015. As of this filing, we have not completed the goodwill impairment analysis, due to the complexities involved in determining the implied fair value of goodwill in the second step of the goodwill impairment test. However, based on the work performed to date, we have concluded that an impairment is probable and can be reasonably estimated. Accordingly, we recorded a full impairment of our remaining goodwill in the fourth quarter of 2015 of $3.7 million. We expect to finalize the goodwill impairment analysis during the first quarter of 2016 and any resulting adjustment to the impairment will be recorded at that time.
The decrease in interest expense during the year ended December 31, 2015 compared to the year ended December 31, 2014 was due to a decrease in the average effective interest rate on our debt, partially offset by an increase in the average balance of long-term debt. The decrease in the average effective interest rate was primarily due to the redemption of $355.0 million aggregate principal amount of 4.25% convertible senior notes (the “4.25% Notes”), which including the debt discount had an effective interest rate of 11.67%, in the second quarter of 2014 with borrowings from our revolving credit facility.
The change in other (income) expense, net, during the year ended December 31, 2015 compared to the year ended December 31, 2014 was primarily due to a $4.0 million decrease in gain on sale of property, plant and equipment partially offset by a decrease in expensed acquisition costs related to the August 2014 MidCon Acquisition and April 2014 MidCon Acquisition.
Income Taxes
(dollars in thousands)
Years Ended December 31, | Increase (Decrease) | |||||||||
2015 | 2014 | |||||||||
Provision for (benefit from) income taxes | $ | 53,189 | $ | (28,066 | ) | (290 | )% | |||
Effective tax rate | (50.1 | )% | 62.1 | % | (112.2 | )% | ||||
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The increase in income tax expense during the year ended December 31, 2015 compared to the year ended December 31, 2014 was primarily attributable to $90.8 million in tax expense recorded for the foreign tax credit write off and valuation allowances on the remaining foreign tax credits and state NOLs, which were allocated to Exterran Corporation upon completion of the Spin-off and a $3.0 million state tax benefit recognized during the year ended December 31, 2014 for amendments to prior years’ tax returns.
Discontinued Operations
(dollars in thousands)
Years Ended December 31, | Increase (Decrease) | |||||||||
2015 | 2014 | |||||||||
Income from discontinued operations, net of tax | $ | 60,408 | $ | 142,995 | (58 | )% | ||||
Income from discontinued operations, net of tax, during the years ended December 31, 2015 and 2014 includes the results of the Exterran Corporation businesses for periods prior to the Spin-off on November 3, 2015 and results from our contract water treatment business.
As discussed in Note 2 (“Discontinued Operations”) to our Financial Statements, on November 3, 2015 we completed the Spin-off of Exterran Corporation. We generated income from discontinued operations, net of tax of $60.5 million and $143.5 million during the years ended December 31, 2015 and 2014, respectively, related to the operations of Exterran Corporation. The decrease in income from discontinued operations, net of tax is primarily due to a decrease in gross margin in all of Exterran Corporation’s segments, an increase in restructuring charges, including costs related to the Spin-off, an increase in foreign currency losses and an increase in long-lived asset impairment. These decreases were partially offset by decreases in SG&A, income tax and depreciation and amortization expense. All of these factors were impacted by the timing of the Spin-off of Exterran Corporation and partial year results in the current year.
The results of Exterran Corporation include its previously nationalized Venezuelan joint venture assets and Venezuelan subsidiary assets which were sold to PDVSA Gas in 2012. Exterran Corporation received installment payments, including an annual charge, totaling $71.8 million and $87.3 million during the years ended December 31, 2015 and 2014, respectively.
In December 2013, we abandoned our contract water treatment business as part of our continued emphasis on simplification and focus on our core businesses. We generated loss from discontinued operations, net of tax of $0.1 million and $0.5 million during the year ended December 31, 2015 and 2014, respectively related to our contract water treatment business.
Net Income Attributable to the Noncontrolling Interest
(dollars in thousands)
Years Ended December 31, | Increase (Decrease) | |||||||||
2015 | 2014 | |||||||||
Net (income) loss attributable to the noncontrolling interest | $ | (6,852 | ) | $ | (27,716 | ) | (75 | )% | ||
Noncontrolling interest comprises the portion of the Partnership’s earnings that are applicable to the Partnership’s publicly-held limited partner interest. As of December 31, 2015 and 2014 public unitholders held an ownership interest in the Partnership of 59% and 63%, respectively. The decrease in net income attributable to the noncontrolling interest during the year ended December 31, 2015 compared to the year ended December 31, 2014 was primarily due to an increase in long-lived asset impairment, interest expense, depreciation and amortization and the impairment of goodwill, along with our increased ownership percentage in the Partnership, partially offset by an increase in gross margin of the Partnership as a result of the April 2015 Contract Operations Acquisition, and inclusion of full year results from the August 2014 MidCon Acquisition and April 2014 MidCon Acquisition. Our ownership percentage of the Partnership increased during the year ended December 31, 2015 compared to the year ended December 31, 2014 as a result of the April 2015 Contract Operations Acquisition.
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The Year ended December 31, 2014 Compared to the Year ended December 31, 2013
Contract Operations
(dollars in thousands)
Years Ended December 31, | Increase (Decrease) | |||||||||
2014 | 2013 | |||||||||
Revenue | $ | 729,103 | $ | 627,844 | 16 | % | ||||
Cost of sales (excluding depreciation and amortization expense) | 316,142 | 282,489 | 12 | % | ||||||
Gross margin | $ | 412,961 | $ | 345,355 | 20 | % | ||||
Gross margin percentage | 57 | % | 55 | % | 2 | % | ||||
The increase in revenue during the year ended December 31, 2014 compared to the year ended December 31, 2013 was primarily attributable to a 17% increase in average operating horsepower, which included the assets acquired in the August 2014 MidCon Acquisition and the April 2014 MidCon Acquisition as well as organic growth in operating horsepower, and higher rates in 2014, partially offset by a $12.1 million decrease in revenue with little incremental cost due to the termination of three natural gas processing plant contracts during the second quarter of 2013. Gross margin (defined as revenue less cost of sales, excluding depreciation and amortization expense) and gross margin percentage increased during the year ended December 31, 2014 compared to the year ended December 31, 2013 primarily due to the revenue increase explained above. Gross margin, a non-GAAP financial measure, is reconciled, in total, to net income (loss), its most directly comparable financial measure calculated and presented in accordance with GAAP, in Part II, Item 6 (‘Selected Financial Data — Non GAAP Financial Measures’) to this Annual Report on Form 10-K.
Aftermarket Services
(dollars in thousands)
Years Ended December 31, | Increase (Decrease) | |||||||||
2014 | 2013 | |||||||||
Revenue | $ | 230,050 | $ | 234,928 | (2 | )% | ||||
Cost of sales (excluding depreciation and amortization expense) | 188,251 | 188,489 | — | % | ||||||
Gross margin | $ | 41,799 | $ | 46,439 | (10 | )% | ||||
Gross margin percentage | 18 | % | 20 | % | (2 | )% | ||||
The decrease in revenue during the year ended December 31, 2014 compared to the year ended December 31, 2013 was primarily due to a decrease in service activities partially offset by an increase in part sales. Gross margin and gross margin percentage decreased during the year ended December 31, 2014 compared to the year ended December 31, 2013 primarily due to the revenue decrease described above and a $1.1 million increase in expense for inventory reserves.
Costs and Expenses
(dollars in thousands)
Years Ended December 31, | Increase (Decrease) | |||||||||
2014 | 2013 | |||||||||
Selling, general and administrative | $ | 132,651 | $ | 118,851 | 12 | % | ||||
Depreciation and amortization | 212,268 | 187,476 | 13 | % | ||||||
Long-lived asset impairment | 42,828 | 16,696 | 157 | % | ||||||
Restructuring charges | 5,394 | — | — | % | ||||||
Interest expense | 112,273 | 112,194 | — | % | ||||||
Other (income) expense, net | (5,475 | ) | (22,535 | ) | (76 | )% | ||||
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The increase in SG&A expense during the year ended December 31, 2014 compared to the year ended December 31, 2013 was primarily due to an increase in compensation and benefits costs, an increase in state and local taxes and an increase in professional fees. SG&A as a percentage of revenue was 14% during the years ended December 31, 2014 and 2013.
Depreciation and amortization expense during the year ended December 31, 2014 compared to the year ended December 31, 2013 increased primarily due to an increase in property, plant and equipment and intangible asset additions, including the assets acquired in the August 2014 MidCon Acquisition and the April 2014 MidCon Acquisition.
During the year ended December 31, 2014, we evaluated the future deployment of our idle fleet and determined to retire and either sell or re-utilize the key components of approximately 290 idle compressor units, representing approximately 112,000 horsepower, previously used to provide services in our U.S. contract operations segment. As a result, we performed an impairment review and recorded a $30.4 million asset impairment to reduce the book value of each unit to its estimated fair value. The fair value of each unit was estimated based on either the expected net sale proceeds compared to other fleet units we recently sold and/or a review of other units recently offered for sale by third parties, or the estimated component value of the equipment we plan to use.
In connection with our fleet review during 2014, we evaluated for impairment idle units that had been culled from our fleet in prior years and were available for sale. Based upon that review, we reduced the expected proceeds from disposition for certain of the remaining units. This resulted in an additional impairment of $11.7 million to reduce the book value of each unit to its estimated fair value.
During the year ended December 31, 2014, we evaluated other long-lived assets for impairment and recorded long-lived asset impairments of $0.7 million on these assets.
During the year ended December 31, 2013, we evaluated the future deployment of our idle fleet and determined to retire and either sell or re-utilize the key components of approximately 280 idle compressor units, representing approximately 76,000 horsepower, previously used to provide services in our U.S. contract operations segment. As a result, we performed an impairment review and recorded a $14.9 million asset impairment to reduce the book value of each unit to its estimated fair value. The fair value of each unit was estimated based on either the expected net sale proceeds compared to other fleet units we recently sold and/or a review of other units recently offered for sale by third parties, or the estimated component value of the equipment we plan to use.
During the year ended December 31, 2013, we evaluated other long-lived assets for impairment and recorded long-lived asset impairments of $1.8 million on these assets.
In January 2014, we announced a plan to centralize our make-ready operations to improve the cost and efficiency of our shops and further enhance the competitiveness of our fleet of compressors. As part of this plan, we examined both recent and anticipated changes in the U.S. market, including the throughput demand of our shops and the addition of new equipment to our fleet. To better align our costs and capabilities with the current market, we determined to close several of our make-ready shops. The centralization of our make-ready operations was completed in the second quarter of 2014. During the year ended December 31, 2014, we incurred $5.4 million of restructuring charges primarily related to termination benefits and a non-cash write-down of inventory associated with the centralization of our make-ready operations. See Note 13 (“Restructuring Charges”) to our Financial Statements for further discussion of these charges.
Interest expense during the year ended December 31, 2014 compared to the year ended December 31, 2013 remained relatively flat due to an increase in the average balance of long-term debt, partially offset by a decrease in the weighted average effective interest rate on our debt. The decrease in the weighted average effective interest rate was primarily due to the redemption of $355.0 million aggregate principal amount of 4.25% convertible senior notes (the “4.25% Notes”) in the second quarter of 2014 with borrowings from our revolving credit facility, including the impact of a decrease in amortization of the debt discount on the 4.25% Notes in 2014, partially offset by the issuance of $350.0 million aggregate principal amount of the Partnership’s 6% senior notes in April 2014 (the “Partnership 2014 Notes”) and the issuance of $350.0 million aggregate principal amount of the Partnership’s 6% senior notes in March 2013 (the “Partnership 2013 Notes”).
The change in other (income) expense, net, during the year ended December 31, 2014 compared to the year ended December 31, 2013 was primarily due to an $18.4 million decrease in gain on sale of property, plant and equipment in 2014.
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Income Taxes
(dollars in thousands)
Years Ended December 31, | Increase (Decrease) | |||||||||
2014 | 2013 | |||||||||
Benefit from income taxes | $ | (28,066 | ) | $ | (17,840 | ) | 57 | % | ||
Effective tax rate | 62.1 | % | 85.4 | % | (23.3 | )% | ||||
The increase in benefit from income taxes during the year ended December 31, 2014 compared to the year ended December 31, 2013 was primarily due to an increase in pre-tax loss in 2014 and a $3.0 million state tax benefit recognized in2014 for amendments to prior years’ tax returns. The state tax benefit was partially offset by an income tax reserve against a portion of the refund claimed in the amended prior year tax return.
Discontinued Operations
(dollars in thousands)
Years Ended December 31, | Increase (Decrease) | |||||||||
2014 | 2013 | |||||||||
Income from discontinued operations, net of tax | $ | 142,995 | $ | 158,790 | (10 | )% | ||||
Income from discontinued operations, net of tax, during the years ended December 31, 2014 and 2013 includes the results of the Exterran Corporation businesses for periods prior to the Spin-off on November 3, 2015 and results from our contract water treatment business.
As discussed in Note 2 (“Discontinued Operations”) to our Financial Statements, on November 3, 2015 we completed the Spin-off of Exterran Corporation. We generated income from discontinued operations, net of tax of $143.0 million and $158.8 million during the years ended December 31, 2014 and 2013, respectively, related to the operations of Exterran Corporation. The decrease in income from discontinued operations, net of tax is primarily due to an increase in depreciation and amortization expense and a decrease in fabrication gross margins partially offset by an increase in international contract operations gross margin and a decrease in income tax expense.
The results of Exterran Corporation include its previously-nationalized Venezuelan joint venture assets and Venezuelan subsidiary assets which were sold to PDVSA Gas. Exterran Corporation received installment payments, including an annual charge, totaling $87.3 million and $88.3 million during the years ended December 31, 2014 and 2013, respectively. The proceeds from the sale of the assets are not subject to Venezuelan national taxes due to an exemption allowed under the Venezuelan Reserve Law applicable to expropriation settlements. In addition, and in connection with the sale, Exterran Corporation and the Venezuelan government agreed to waive rights to assert certain claims against each other.
In December 2013, we abandoned our contract water treatment business as part of our continued emphasis on simplification and focus on our core businesses. We generated loss from discontinued operations, net of tax of $0.5 million and $2.1 million during the year ended December 31, 2014 and 2013, respectively related to our contract water treatment business. During the year ended December 31, 2013, we evaluated our contract water treatment business and recorded impairment charges of $2.4 million.
Net Income Attributable to the Noncontrolling Interest
(dollars in thousands)
Years Ended December 31, | Increase (Decrease) | |||||||||
2014 | 2013 | |||||||||
Net (income) loss attributable to the noncontrolling interest | $ | (27,716 | ) | $ | (32,578 | ) | (15 | )% | ||
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Noncontrolling interest comprises the portion of the Partnership’s earnings that are applicable to the Partnership’s publicly-held limited partner interest. As of December 31, 2014 and 2013 public unitholders held an ownership interest in the Partnership of 63% and 59%, respectively. The decrease in net income attributable to the noncontrolling interest during the year ended December 31, 2014 compared to the year ended December 31, 2013 was primarily due to a decrease in earnings of the Partnership as a result of increases in interest expense and long-lived asset impairment and the termination of two natural gas processing plant contracts during the second quarter of 2013, partially offset by inclusion of the results of the August 2014 MidCon Acquisition, the April 2014 MidCon Acquisition, the March 2013 Contract Operations Acquisition and our decreased ownership percentage in the Partnership. Our ownership percentage of the Partnership decreased during the year ended December 31, 2014 compared to the year ended December 31, 2013 as a result of units sold in a public offering to fund the April 2014 MidCon Acquisition.
Liquidity and Capital Resources
Our unrestricted cash balance was $1.6 million at December 31, 2015 compared to $0.4 million at December 31, 2014. Working capital decreased to $150.2 million at December 31, 2015 from $575.7 million at December 31, 2014. The decrease in working capital was primarily due to decreases in current assets and current liabilities associated with discontinued operations as a result of the transfer of assets and liabilities to Exterran Corporation upon completion of the Spin-off.
Our cash flows from operating, investing and financing activities, as reflected in the consolidated statements of cash flows, are summarized in the table below (in thousands):
Years Ended December 31, | |||||||
2015 | 2014 | ||||||
Net cash provided by (used in) continuing operations: | |||||||
Operating activities | $ | 322,474 | $ | 216,017 | |||
Investing activities | (237,375 | ) | (866,442 | ) | |||
Financing activities | (97,516 | ) | 555,047 | ||||
Effect of exchange rate changes on cash and cash equivalents | — | (3,925 | ) | ||||
Discontinued operations | 13,602 | 99,210 | |||||
Net change in cash and cash equivalents | $ | 1,185 | $ | (93 | ) | ||
Operating Activities. The increase in net cash provided by operating activities from continuing operations during the year ended December 31, 2015 compared to the year ended December 31, 2014 was primarily due to improved gross margins and changes in assets and liabilities.
Investing Activities. The decrease in net cash used in investing activities from continuing operations during the year ended December 31, 2015 compared to the year ended December 31, 2014 was primarily attributable to $494.8 million paid for the August 2014 MidCon Acquisition and the April 2014 MidCon Acquisition during the year ended December 31, 2014 and a $127.7 million decrease in capital expenditures during the current year.
Financing Activities. The decrease in net cash provided by financing activities from continuing operations during the year ended December 31, 2015 compared to the year ended December 31, 2014 was primarily due to net proceeds received from Exterran Corporation in 2015 of $480.1 million, offset by net repayments of long-term debt in 2015 of $444.6 million compared to net borrowings in 2014 of $505.8 million and a $168.3 million decrease in net proceeds received from public offerings by the Partnership of its common units.
Discontinued Operations. The decrease in net cash provided by discontinued operations during the year ended December 31, 2015 compared to year ended December 31, 2014 was primarily attributable to the decrease in income from discontinued operations discussed previously and an increase in investing cash flows used in discontinued operations prior to completion of the Spin-off of Exterran Corporation in November 2015.
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Capital Requirements. Our contract operations business is capital intensive, requiring significant investment to maintain and upgrade existing operations. Our capital spending is primarily dependent on the demand for our contract operations services and the availability of the type of compression equipment required for us to render those contract operations services to our customers. Our capital requirements have consisted primarily of, and we anticipate will continue to consist of, the following:
• | growth capital expenditures, which are made to expand or to replace partially or fully depreciated assets or to expand the operating capacity or revenue generating capabilities of existing or new assets, whether through construction, acquisition or modification; and |
• | maintenance capital expenditures, which are made to maintain the existing operating capacity of our assets and related cash flows further extending the useful lives of the assets. |
The majority of our growth capital expenditures are related to the acquisition cost of new compressor units that we add to our fleet. In addition, growth capital expenditures can also include the upgrading of major components on an existing compressor unit where the current configuration of the compressor unit is no longer in demand and the compressor is not likely to return to an operating status without the capital expenditures. These latter expenditures substantially modify the operating parameters of the compressor unit such that it can be used in applications for which it previously was not suited. Maintenance capital expenditures are related to major overhauls of significant components of a compressor unit, such as the engine, compressor and cooler, that return the components to a like new condition, but do not modify the applications for which the compressor unit was designed.
Growth capital expenditures were $154.5 million, $291.8 million and $194.7 million during the years ended December 31, 2015, 2014 and 2013, respectively. The decrease in growth capital expenditures during the year ended December 31, 2015 compared to the year ended December 31, 2014 was primarily due to a decrease in investment in new compression equipment as a result of our customer’s reduced capital spending in 2015 compared to 2014 as a result of the significant decline in oil and natural gas prices since the third quarter of 2014. The increase in growth capital expenditures during the year ended December 31, 2014 compared to the year ended December 31, 2013 was primarily due to increases in investment in new compression equipment driven primarily by increased demand for natural gas compression in certain shale plays and areas focused on the production of oil and natural gas liquids. This activity increased the utilization of our compressor units that are more suitable to these plays.
Maintenance capital expenditures were $75.0 million, $71.8 million and $73.6 million during the years ended December 31, 2015, 2014 and 2013, respectively. Maintenance capital expenditures remained relatively flat primarily as a result of routine scheduled overhaul activities. We intend to grow our business both organically and through third-party acquisitions. The Partnership completed the August 2014 MidCon Acquisition and the April 2014 MidCon Acquisition during the year ended December 31, 2014. If we are successful in growing our business in the future, we would expect our maintenance capital expenditures to increase over the long term.
We generally invest funds necessary to purchase fleet additions when our idle equipment cannot be reconfigured to economically fulfill a project’s requirements and the new equipment expenditure is expected to generate economic returns over its expected useful life that exceeds our targeted return on capital. We currently plan to spend approximately $120.0 million to $130.0 million in net capital expenditures during 2016, including (1) approximately $30.0 million to $50.0 million on growth capital expenditures and (2) approximately $70.0 million to $75.0 million on equipment maintenance capital expenditures. Net capital expenditures are net of used fleet sales.
Our Capital Structure Following the Spin-Off.
In October 2015, in connection with the Spin-off, we entered into a five-year, $350.0 million revolving credit facility (the “Credit Facility”). The Credit Facility will mature in November 2020. On November 3, 2015, we terminated our former credit facility and repaid $326.5 million in borrowings and accrued and unpaid interest outstanding on the repayment date.
In connection with the Spin-off, Exterran Corporation entered into a new $925.0 million credit facility, consisting of a $680.0 million revolving credit facility and a $245.0 million term loan facility (collectively, the “Exterran Corporation Credit Facility”) that became available on November 3, 2015. Exterran Corporation transferred the net proceeds from the borrowings under the Exterran Corporation Credit Facility to us to allow for our repayment of a portion of our indebtedness prior to the Spin-off.
On December 4, 2015, we redeemed for cash the $350.0 million aggregate principal amount of 7.25% senior notes due December 2018 (the “7.25% Notes”) at a redemption price equal to 101.813% of the principal amount thereof plus accrued but unpaid interest to the redemption date.
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Under our separation and distribution agreement with Exterran Corporation, we have the right to receive payments from a subsidiary of Exterran Corporation based on a notional amount corresponding to payments received by Exterran Corporation’s subsidiaries from PDVSA Gas in respect of the sale of Exterran Corporation’s subsidiaries’ and joint ventures’ previously nationalized assets. In January 2016, Exterran Corporation received an additional installment payment, including an annual charge, of $5.2 million from PDVSA Gas relating to its previously nationalized Venezuelan joint ventures’ assets and transferred cash to us equal to that amount in January 2016. Additionally, we also have the right under the separation and distribution agreement to receive a $25.0 million cash payment from a subsidiary of Exterran Corporation promptly following the occurrence of a qualified capital raise as defined in the Exterran Corporation credit agreement.
Long-Term Debt. As of December 31, 2015, we had approximately $1.6 billion in outstanding debt obligations, consisting of $166.5 million outstanding under the Credit Facility, $580.5 million outstanding under the Partnership’s revolving credit facility, $150.0 million outstanding under the Partnership’s term loan facility, $346.1 million outstanding under the Partnership 2013 Notes and $345.3 million outstanding under the Partnership 2014 Notes. After taking into account $10.0 million of guarantees through letters of credit, we had undrawn and available capacity of $173.5 million under the Credit Facility as of December 31, 2015.
As described above, October 2015, in connection with the Spin-off, we entered into the Credit Facility. Availability under the Credit Facility was subject to the satisfaction of certain conditions precedent, including (i) the payoff and termination of our former credit facility and (ii) the consummation of the Spin-off on or before January 4, 2016 (the date on which those conditions were satisfied is referred to as the “Archrock Initial Availability Date”). As a result of the completion of the Spin-off, the Archrock Initial Availability Date was November 3, 2015 and the Credit Facility will mature in November 2020. On November 3, 2015, we terminated our former credit facility and repaid $326.5 million in borrowings and accrued and unpaid interest outstanding on the repayment date.
Borrowings under the Credit Facility bear interest at a base rate or the London Interbank Offered Rate (“LIBOR”), at our option, plus an applicable margin. Depending on our Total Leverage Ratio (as defined in the credit agreement), the applicable margin for revolving loans varies (i) in the case of LIBOR loans, from 1.75% to 2.75% and (ii) in the case of base rate loans, from 0.75% to 1.75%. The base rate is the highest of the prime rate announced by Wells Fargo Bank, National Association, the Federal Funds Rate plus 0.5% and one-month LIBOR plus 1.0%. At December 31, 2015, all amounts outstanding under the Credit Facility were LIBOR loans and the applicable margin was 1.75%. The weighted average annual interest rate at both December 31, 2015 and 2014 on the outstanding balance under the Credit Facility was 2.1% and 1.7%, respectively.
Archrock, Inc. (the “Parent”) and our Significant Domestic Subsidiaries (as defined in the credit agreement) guarantee the debt under the Credit Facility. Borrowings under the Credit Facility are secured by substantially all of the personal property assets and certain real property assets of the Parent and our Significant Domestic Subsidiaries, including all of the equity interests of our U.S. subsidiaries (other than certain excluded subsidiaries). The Partnership does not guarantee the debt under the Credit Facility, its assets are not collateral under the Credit Facility and the general partner units in the Partnership are not pledged under the Credit Facility. Subject to certain conditions, at our request, and with the approval of the lenders, the aggregate commitments under the Credit Facility may be increased by up to an additional $100 million.
The Credit Facility contains various covenants with which we or certain of our subsidiaries must comply, including, but not limited to, limitations on the incurrence of indebtedness, investments, liens on assets, repurchasing equity and making distributions, transactions with affiliates, mergers, consolidations, dispositions of assets and other provisions customary in similar types of agreements. We are also subject to financial covenants, including a ratio of EBITDA (as defined in the credit agreement) to Total Interest Expense (as defined in the credit agreement) of not less than 2.25 to 1.0, a ratio of consolidated Total Debt (as defined in the credit agreement) to EBITDA of not greater than 4.25 to 1.0 (subject to a temporary increase to 4.75 to 1.0 for any quarter during which an acquisition meeting certain thresholds is completed and for the following two quarters after the acquisition closes). As of December 31, 2015, we maintained a 33.3 to 1.0 EBITDA to Total Interest Expense ratio and a 1.3 to 1.0 consolidated Total Debt to EBITDA ratio. If we were to anticipate non-compliance with these financial ratios, we may take actions to maintain compliance with them, possibly including reductions in our general and administrative expenses, capital expenditures or the payment of cash dividends at our current dividend rate. If we fail to remain in compliance with our financial covenants we would be in default under our debt agreements. A default under one or more of our debt agreements would trigger cross-default provisions under certain of our other debt agreements, which would accelerate our obligation to repay our indebtedness under those agreements. In addition, if we experience a material adverse effect on our assets, liabilities, financial condition, business or operations that, taken as a while, impacts our ability to perform our obligations under our debt agreements, this could lead to a default under our debt agreements. As of December 31, 2015, we were in compliance with all financial covenants under the Credit Facility.
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Also as described above, on December 4, 2015, we redeemed for cash the 7.25% Notes at a redemption price equal to 101.813% of the principal amount thereof plus accrued but unpaid interest to the redemption date for $369.2 million. Upon redemption, the 7.25% Notes were no longer deemed outstanding, interest ceased to accrue thereon and all rights of the holders of the 7.25% Notes ceased to exist. We financed the redemption of the 7.25% Notes through borrowings under our revolving credit facility. As a result of the redemption, we expensed the $6.3 million call premium and $2.9 million of unamortized deferred financing costs associated with the 7.25% Notes in the fourth quarter of 2015, which is reflected in debt extinguishment costs in our consolidated statements of operations.
In November 2010, the Partnership amended and restated its Partnership Credit Agreement to provide for a five-year $550.0 million senior secured credit facility, consisting of a $400.0 million revolving credit facility and a $150.0 million term loan facility. The revolving borrowing capacity under this facility increased to $550.0 million in March 2011 and to $750.0 million in March 2012. The Partnership amended the Partnership Credit Agreement in March 2013 to reduce the borrowing capacity under its revolving credit facility to $650.0 million and extend the maturity date of the term loan and revolving credit facilities to May 2018. In February 2015, the Partnership amended its Partnership Credit Agreement, which among other things, increased the borrowing capacity under its revolving credit facility by $250.0 million to $900.0 million. As of December 31, 2015, the Partnership had undrawn and available capacity of $319.5 million under its revolving credit facility.
The Partnership’s revolving credit and term loan facilities bear interest at a base rate or LIBOR, at the Partnership’s option, plus an applicable margin. Depending on the Partnership’s leverage ratio, the applicable margin for the revolving and term loans varies (i) in the case of LIBOR loans, from 2.0% to 3.0% and (ii) in the case of base rate loans, from 1.0% to 2.0%. The base rate is the highest of the prime rate announced by Wells Fargo Bank, National Association, the Federal Funds Effective Rate plus 0.5% and one-month LIBOR plus 1.0%. At December 31, 2015, all amounts outstanding under these facilities were LIBOR loans and the applicable margin was 2.5%. The weighted average annual interest rate on the outstanding balance under these facilities at December 31, 2015 and 2014, excluding the effect of interest rate swaps, was 2.8% and 2.7%, respectively. During the years ended December 31, 2015 and 2014, the average daily debt balance under these facilities was $667.3 million and $438.5 million, respectively.
Borrowings under the Partnership Credit Agreement are secured by substantially all of the U.S. personal property assets of the Partnership and its Significant Domestic Subsidiaries (as defined in the Partnership Credit Agreement), including all of the membership interests of the Partnership’s Domestic Subsidiaries (as defined in the Partnership Credit Agreement). Subject to certain conditions, at the Partnership’s request, and with the approval of the lenders, the aggregate commitments under the Partnership Credit Agreement may be increased by up to an additional $50 million.
The Partnership Credit Agreement contains various covenants with which the Partnership must comply, including, but not limited to, restrictions on the use of proceeds from borrowings and limitations on the Partnership’s ability to incur additional indebtedness, engage in transactions with affiliates, merge or consolidate, sell assets, make certain investments and acquisitions, make loans, grant liens, repurchase equity and pay dividends and distributions. The Partnership Credit Agreement also contains various covenants requiring mandatory prepayments from the net cash proceeds of certain asset transfers. The Partnership must maintain various consolidated financial ratios, including a ratio of EBITDA (as defined in the Partnership Credit Agreement) to Total Interest Expense (as defined in the Partnership Credit Agreement) of not less than 2.75 to 1.0, a ratio of Total Debt (as defined in the Partnership Credit Agreement) to EBITDA of not greater than 5.25 to 1.0 (subject to a temporary increase to 5.5 to 1.0 for any quarter during which an acquisition meeting certain thresholds is completed and for the following two quarters after the acquisition closes) and a ratio of Senior Secured Debt (as defined in the Partnership Credit Agreement) to EBITDA of not greater than 4.0 to 1.0. Because the April 2015 Contract Operations Acquisition closed during the second quarter of 2015, the Partnership’s Total Debt to EBITDA ratio threshold was temporarily increased to 5.5 to 1.0 during the quarter ended June 30, 2015 and continued at that level through December 31, 2015, reverting to 5.25 to 1.0 for the quarter ending March 31, 2016 and subsequent quarters. As of December 31, 2015, the Partnership maintained a 4.5 to 1.0 EBITDA to Total Interest Expense ratio, 4.5 to 1.0 Total Debt to EBITDA ratio and a 2.3 to 1.0 Senior Secured Debt to EBITDA ratio. If the Partnership were to anticipate non-compliance with these financial ratios, the Partnership may take actions to maintain compliance with them, possibly including a reduction in general and administrative expenses, capital expenditures or the payment of cash distributions at its current distribution rate to its unit holders, including us. A reduction in the amount of cash distributions we receive from the Partnership would reduce the amount of cash available for payment of our debt, payment of dividends and the funding of our business requirements. A default under one of the Partnership’s debt agreements would trigger cross-default provisions under the Partnership’s other debt agreements, which would accelerate the Partnership’s obligation to repay its indebtedness under those agreements. In addition, a material adverse effect with respect to the Partnership’s assets, liabilities, financial condition, business or operations that, taken as a whole, impacts the Partnership’s ability to perform its obligations under the Partnership Credit Agreement, could lead to a default under that agreement. As of December 31, 2015, the Partnership was in compliance with all financial covenants under the Partnership Credit Agreement.
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In March 2013, the Partnership issued $350.0 million aggregate principal amount of the Partnership 2013 Notes. The Partnership used the net proceeds of $336.9 million, after original issuance discount and issuance costs, to repay borrowings outstanding under its revolving credit facility. The Partnership 2013 Notes were issued at an original issuance discount of $5.5 million, which is being amortized using the effective interest method at an interest rate of 6.25% over their term. In January 2014, holders of the Partnership 2013 Notes exchanged their Partnership 2013 Notes for registered notes with the same terms.
Prior to April 1, 2017, the Partnership may redeem all or a part of the Partnership 2013 Notes at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make-whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. In addition, the Partnership may redeem up to 35% of the aggregate principal amount of the Partnership 2013 Notes prior to April 1, 2016 with the net proceeds of one or more equity offerings at a redemption price of 106.00% of the principal amount of the Partnership 2013 Notes, plus any accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the Partnership 2013 Notes issued under the indenture remains outstanding after such redemption and the redemption occurs within 180 days of the date of the closing of such equity offering. On or after April 1, 2017, the Partnership may redeem all or a part of the Partnership 2013 Notes at redemption prices (expressed as percentages of principal amount) equal to 103.00% for the twelve-month period beginning on April 1, 2017, 101.500% for the twelve-month period beginning on April 1, 2018 and 100.00% for the twelve-month period beginning on April 1, 2019 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date of the Partnership 2013 Notes.
In April 2014, the Partnership issued $350.0 million aggregate principal amount of the Partnership 2014 Notes. The Partnership received net proceeds of $337.4 million, after original issuance discount and issuance costs, from this offering, which it used to fund a portion of the April 2014 MidCon Acquisition and repay borrowings under its revolving credit facility. The Partnership 2014 Notes were issued at an original issuance discount of $5.7 million, which is being amortized using the effective interest method at an interest rate of 6.25% over their term. In February 2015, holders of the Partnership 2014 Notes exchanged their Partnership 2014 Notes for registered notes with the same terms.
Prior to April 1, 2018, the Partnership may redeem all or a part of the Partnership 2014 Notes at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make-whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. In addition, the Partnership may redeem up to 35% of the aggregate principal amount of the Partnership 2014 Notes prior to April 1, 2017 with the net proceeds of one or more equity offerings at a redemption price of 106.00% of the principal amount of the Partnership 2014 Notes, plus any accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the Partnership 2014 Notes issued under the indenture remains outstanding after such redemption and the redemption occurs within 180 days of the date of the closing of such equity offering. On or after April 1, 2018, the Partnership may redeem all or a part of the Partnership 2014 Notes at redemption prices (expressed as percentages of principal amount) equal to 103.00% for the twelve-month period beginning on April 1, 2018, 101.500% for the twelve-month period beginning on April 1, 2019 and 100.00% for the twelve-month period beginning on April 1, 2020 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date of the Partnership 2014 Notes.
The Partnership 2013 Notes and the Partnership 2014 Notes are guaranteed on a senior unsecured basis by all of the Partnership’s existing subsidiaries (other than Archrock Partners Finance Corp., which is a co-issuer of the Partnership 2013 Notes and the Partnership 2014 Notes) and certain of the Partnership’s future subsidiaries. The Partnership 2013 Notes and the Partnership 2014 Notes and the guarantees, respectively, are the Partnership’s and the guarantors’ general unsecured senior obligations, rank equally in right of payment with all of the Partnership’s and the guarantors’ other senior obligations, and are effectively subordinated to all of the Partnership’s and the guarantors’ existing and future secured debt to the extent of the value of the collateral securing such indebtedness. In addition, the Partnership 2013 Notes and the Partnership 2014 Notes and guarantees are effectively subordinated to all existing and future indebtedness and other liabilities of any future non-guarantor subsidiaries.
The Partnership has entered into interest rate swap agreements to offset changes in expected cash flows due to fluctuations in the interest rates associated with its variable rate debt. At December 31, 2015, the Partnership was a party to interest rate swaps with a notional value of $500.0 million pursuant to which it makes fixed payments and receives floating payments. The Partnership’s interest rate swaps expire over varying dates, with interest rate swaps having a notional amount of $300.0 million expiring in May 2018, interest rate swaps having a notional amount of $100.0 million expiring in May 2019 and the remaining interest rate swaps having a notional amount of $100.0 million expiring in May 2020. As of December 31, 2015, the weighted average effective fixed interest rate on the interest rate swaps was 1.6%. See Part II, Item 7A “Quantitative and Qualitative Disclosures About Market Risk” of this Annual Report on Form 10-K for further discussion of the interest rate swap agreements.
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We may from time to time seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for equity securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
Historically, we have financed capital expenditures with a combination of net cash provided by operating and financing activities. Our ability to access the capital markets may be restricted at a time when we would like, or need, to do so, which could have an adverse impact on our ability to maintain our operations and to grow. If any of our lenders become unable to perform their obligations under our credit facilities, our borrowing capacity under these facilities could be reduced. Inability to borrow additional amounts under those facilities could limit our ability to fund our future growth and operations. We expect that net cash provided by operating activities and borrowings under our credit facilities will be sufficient to meet our liquidity needs through December 31, 2016; however, to the extent it is not, we may seek additional external financing.
Dividends. On January 26, 2016, our board of directors declared a quarterly dividend of $0.1875 per share of common stock, which was paid on February 16, 2016 to stockholders of record at the close of business on February 9, 2016. Any future determinations to pay cash dividends to our stockholders will be at the discretion of our board of directors and will be dependent upon our financial condition and results of operations, credit and loan agreements in effect at that time and other factors deemed relevant by our board of directors.
Partnership Distributions to Unitholders. The Partnership’s partnership agreement requires it to distribute all of its “available cash” quarterly. Under the partnership agreement, available cash is defined generally to mean, for each fiscal quarter, (i) cash on hand at the Partnership at the end of the quarter in excess of the amount of reserves its general partner determines is necessary or appropriate to provide for the conduct of its business, to comply with applicable law, any of its debt instruments or other agreements or to provide for future distributions to its unitholders for any one or more of the upcoming four quarters, plus, (ii) if the Partnership’s general partner so determines, all or a portion of the Partnership’s cash on hand on the date of determination of available cash for the quarter.
Through our ownership of common units and all of the equity interests in the Partnership’s general partner, we expect to receive cash distributions from the Partnership.
Under the terms of the partnership agreement, there is no guarantee that unitholders will receive quarterly distributions from the Partnership. The Partnership’s distribution policy, which may be changed at any time, is subject to certain restrictions, including (i) restrictions contained in the Partnership’s revolving credit facility, (ii) the Partnership’s general partner’s establishment of reserves to fund future operations or cash distributions to the Partnership’s unitholders, (iii) restrictions contained in the Delaware Revised Uniform Limited Partnership Act and (iv) the Partnership’s lack of sufficient cash to pay distributions.
On January 26, 2016, the board of directors of Archrock GP LLC, the general partner of the Partnership’s general partner, approved a cash distribution by the Partnership of $0.5725 per limited partner unit, or approximately $39.7 million, including distributions to the Partnership’s general partner on its incentive distribution rights. The distribution covers the period from October 1, 2015 through December 31, 2015. The record date for this distribution was February 9, 2016 and payment was made on February 12, 2016.
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Contractual Obligations. The following table summarizes our cash contractual obligations as of December 31, 2015 and the effect such obligations are expected to have on our liquidity and cash flow in future periods (in thousands):
Total | 2016 | 2017-2018 | 2019-2020 | Thereafter | |||||||||||||||
Long-term debt (1): | |||||||||||||||||||
Revolving credit facility due November 2020 | $ | 166,500 | $ | — | $ | — | 166,500 | $ | — | ||||||||||
Partnership’s revolving credit facility due May 2018 | 580,500 | — | 580,500 | — | — | ||||||||||||||
Partnership’s term loan facility due May 2018 | 150,000 | — | 150,000 | — | — | ||||||||||||||
Partnership’s 6% senior notes due April 2021 (2) | 350,000 | — | — | — | 350,000 | ||||||||||||||
Partnership’s 6% senior notes due October 2022 (3) | 350,000 | — | — | — | 350,000 | ||||||||||||||
Total long-term debt | 1,597,000 | — | 730,500 | 166,500 | 700,000 | ||||||||||||||
Interest on long-term debt (4) | 339,577 | 74,892 | 131,513 | 91,172 | 42,000 | ||||||||||||||
Purchase commitments | 26,028 | 25,999 | 29 | — | — | ||||||||||||||
Facilities and other operating leases | 18,304 | 5,591 | 7,602 | 3,230 | 1,881 | ||||||||||||||
Total contractual obligations | $ | 1,936,621 | $ | 74,924 | $ | 862,021 | $ | 257,675 | $ | 742,002 | |||||||||
Standby letters of credit | $ | 9,969 | $ | 9,969 | — | — | — | ||||||||||||
(1) | For more information on our long-term debt, see Note 9 (“Long-Term Debt”) to our Financial Statements. |
(2) | Amounts represent the full face value of the Partnership 2013 Notes and are not reduced by the unamortized discount of $3.9 million as of December 31, 2015. |
(3) | Amounts represent the full face value of the Partnership 2014 Notes and are not reduced by the unamortized discount of $4.7 million as of December 31, 2015. |
(4) | Interest amounts calculated using interest rates in effect as of December 31, 2015, including the effect of interest rate swaps. |
At December 31, 2015, $12.0 million of unrecognized tax benefits (including discontinued operations) have been recorded as liabilities in accordance with the accounting standard for income taxes related to uncertain tax positions and we are uncertain as to if or when such amounts may be settled. Related to these unrecognized tax benefits, we have also recorded a liability for potential penalties and interest of $.2 million (including discontinued operations).
Off-Balance Sheet Arrangements
For information on our obligations with respect to letters of credit, see Note 9 (“Long-Term Debt”) to our Financial Statements.
Critical Accounting Estimates
This discussion and analysis of our financial condition and results of operations is based upon the Financial Statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. On an ongoing basis, we evaluate our estimates and accounting policies, including those related to bad debt, inventories, fixed assets, investments, intangible assets, income taxes, revenue recognition and contingencies and litigation. We base our estimates on historical experience and on other assumptions that we believe are reasonable under the circumstances. The results of this process form the basis of our judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions, and these differences can be material to our financial condition, results of operations and liquidity. We describe our significant accounting policies more fully in Note 1 (“Organization and Summary of Significant Accounting Policies”) to our Financial Statements.
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Allowances and Reserves
We maintain allowances for doubtful accounts for estimated losses resulting from the inability of our customers to make required payments. The determination of the collectability of amounts due from our customers requires us to use estimates and make judgments regarding future events and trends, including monitoring our customers’ payment history and current creditworthiness to determine that collectability is reasonably assured, as well as consideration of the overall business climate in which our customers operate. Inherently, these uncertainties require us to make judgments and estimates regarding our customers’ ability to pay amounts due to us in order to determine the appropriate amount of valuation allowances required for doubtful accounts. We review the adequacy of our allowance for doubtful accounts quarterly. We determine the allowance needed based on historical write-off experience and by evaluating significant balances aged greater than 90 days individually for collectability. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. During the years ended December 31, 2015, 2014 and 2013, we recorded bad debt expense of $3.1 million, $1.7 million and a bad debt recovery of $0.2 million, respectively. A five percent change in the allowance for doubtful accounts would have had an impact on income (loss) before income taxes of approximately $0.2 million during the year ended December 31, 2015.
Inventory is a significant component of current assets and is stated at the lower of cost or market. This requires us to record provisions and maintain reserves for excess, slow moving and obsolete inventory. To determine these reserve amounts, we regularly review inventory quantities on hand and compare them to estimates of future product demand, market conditions and production requirements. These estimates and forecasts inherently include uncertainties and require us to make judgments regarding potential outcomes. During 2015, 2014, and 2013, we recorded $4.3 million, $8.9 million and $3.9 million, respectively, in inventory write-downs and reserves for inventory which was obsolete, excess or carried at a price above market value. Significant or unanticipated changes to our estimates and forecasts could impact the amount and timing of any additional provisions for excess or obsolete inventory that may be required. A five percent change in this inventory reserve balance would have had an impact on income (loss) before income taxes of approximately $0.5 million during the year ended December 31, 2015.
Depreciation
Property, plant and equipment are carried at cost. Depreciation for financial reporting purposes is computed on the straight-line basis using estimated useful lives and salvage values. The assumptions and judgments we use in determining the estimated useful lives and salvage values of our property, plant and equipment reflect both historical experience and expectations regarding future use of our assets. The use of different estimates, assumptions and judgments in the establishment of property, plant and equipment accounting policies, especially those involving their useful lives, would likely result in significantly different net book values of our assets and results of operations.
Long-Lived Assets
We review long-lived assets, including property, plant and equipment and identifiable intangibles that are being amortized, for impairment whenever events or changes in circumstances, including the removal of compressor units from our active fleet, indicate that the carrying amount of an asset may not be recoverable. The determination that the carrying amount of an asset may not be recoverable requires us to make judgments regarding long-term forecasts of future revenue and costs related to the assets subject to review. These forecasts are uncertain as they require significant assumptions about future market conditions. Significant and unanticipated changes to these assumptions could require a provision for impairment in a future period. Given the nature of these evaluations and their application to specific assets and specific times, it is not possible to reasonably quantify the impact of changes in these assumptions. An impairment loss exists when estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount. When necessary, an impairment loss is recognized and represents the excess of the asset’s carrying value as compared to its estimated fair value and is charged to the period in which the impairment occurred.
Income Taxes
Our income tax expense, deferred tax assets and liabilities, and reserves for unrecognized tax benefits reflect management’s best assessment of estimated current and future taxes to be paid. We operate in the U.S. only and, as a result, are subject to income taxes in the U.S. only. Significant judgments and estimates are required in determining consolidated income tax expense.
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Deferred income taxes arise from temporary differences between the financial statements and tax basis of assets and liabilities. In evaluating our ability to recover our deferred tax assets within the jurisdiction from which they arise, we consider all available positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax-planning strategies, and results of recent operations. In projecting future taxable income, we begin with historical results adjusted for the results of discontinued operations and changes in accounting policies and incorporate assumptions including the amount of future U.S. federal and state pretax operating income, the reversal of temporary differences and the implementation of feasible and prudent tax-planning strategies. These assumptions require significant judgment about the forecasts of future taxable income and are consistent with the plans and estimates we are using to manage the underlying businesses. In evaluating the objective evidence that historical results provide, we consider three years of cumulative operating income (loss).
Changes in tax laws and rates could also affect recorded deferred tax assets and liabilities in the future. Management is not aware of any such changes that would have a material effect on the Company’s financial position, results of operations or cash flows. The calculation of our tax liabilities involves dealing with uncertainties in the application of complex tax laws and regulations in a multitude of jurisdictions across our operations.
The accounting standard for income taxes provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, on the basis of the technical merits. In addition, guidance is provided on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. We adjust these liabilities when our judgment changes as a result of the evaluation of new information not previously available. Because of the complexity of some of these uncertainties, the ultimate resolution may result in a payment that is materially different from our current estimate of the tax liabilities. These differences will be reflected as increases or decreases to income tax expense in the period in which new information is available.
Contingencies and Litigation
We are substantially self-insured for workers’ compensation, employer’s liability, property, auto liability, general liability and employee group health claims in view of the relatively high per-incident deductibles we absorb under our insurance arrangements for these risks. Losses up to deductible amounts are estimated and accrued based upon known facts, historical trends and industry averages. We review these estimates quarterly and believe such accruals to be adequate. However, insurance liabilities are difficult to estimate due to unknown factors, including the severity of an injury, the determination of our liability in proportion to other parties, the timeliness of reporting of occurrences, ongoing treatment or loss mitigation, general trends in litigation recovery outcomes and the effectiveness of safety and risk management programs. Therefore, if our actual experience differs from the assumptions and estimates used for recording the liabilities, adjustments may be required and would be recorded in the period in which the difference becomes known. As of December 31, 2015 and 2014, we had recorded approximately $5.3 million and $3.7 million, respectively, in insurance claim reserves.
In the ordinary course of business, we are involved in various pending or threatened legal actions. While we are unable to predict the ultimate outcome of these actions, the accounting standard for contingencies requires management to make judgments about future events that are inherently uncertain. We are required to record (and have recorded) a loss during any period in which we believe a contingency is probable and can be reasonably estimated. In making determinations of likely outcomes of pending or threatened legal matters, we consider the evaluation of counsel knowledgeable about each matter.
The impact of an uncertain tax position taken or expected to be taken on an income tax return must be recognized in the financial statements at the largest amount that is more likely than not to be sustained upon examination by the relevant taxing authority. We regularly assess and, if required, establish accruals for income tax as well as non-income tax contingencies pursuant to the applicable accounting standards that could result from assessments of additional tax by taxing jurisdictions in countries where we operate. Tax contingencies are subject to a significant amount of judgment and are reviewed and adjusted on a quarterly basis in light of changing facts and circumstances considering the outcome expected by management. As of December 31, 2015 and 2014, we had recorded approximately $14.8 million and $26.3 million (including penalties and interest and discontinued operations), respectively, of accruals for tax contingencies. Of these amounts, $12.2 million and $17.9 million, respectively, are accrued for income taxes and $2.7 million and $8.4 million, respectively, are accrued for non-income based taxes. If our actual experience differs from the assumptions and estimates used for recording the liabilities, adjustments may be required and would be recorded in the period in which the difference becomes known.
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Subject to the provisions of the tax matters agreement between Exterran Corporation and us, both parties agreed to indemnify the primary obligor of any return for tax periods beginning before and ending before or after the Spin-off (including any ongoing or future amendments and audits for these returns) for the portion of the tax liability (including interest and penalties) that relates to their respective operations reported in the filing. As of December 31, 2015, we have recorded a net $4.2 million indemnification asset (including penalties and interest) related to tax contingencies. Of this amount, $5.7 million is an accrued asset for income taxes and $1.5 million is an accrued liability for non-income based taxes.
Recent Accounting Pronouncements
See Note 21 (“Recent Accounting Developments”) to our Financial Statements.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risks primarily associated with changes in interest rates under our financing arrangements. We use derivative financial instruments to minimize the risks and/or costs associated with financial activities by managing our exposure to interest rate fluctuations on a portion of our debt obligations. We do not use derivative financial instruments for trading or other speculative purposes.
As of December 31, 2015, after taking into consideration interest rate swaps, we had $397.0 million of outstanding indebtedness that was effectively subject to floating interest rates. A 1% increase in the effective interest rate on our outstanding debt subject to floating interest rates at December 31, 2015 would result in an annual increase in our interest expense of approximately $4.0 million.
For further information regarding our use of interest rate swap agreements to manage our exposure to interest rate fluctuations on a portion of our debt obligations, see Note 10 (“Accounting for Derivatives”) to our Financial Statements.
Item 8. Financial Statements and Supplementary Data
The consolidated financial statements and supplementary information specified by this Item are presented in Part IV, Item 15 of this Annual Report on Form 10-K.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Management’s Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this Annual Report on Form 10-K, our principal executive officer and principal financial officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act), which are designed to provide reasonable assurance that we are able to record, process, summarize and report the information required to be disclosed in our reports under the Exchange Act within the time periods specified in the rules and forms of the Securities and Exchange Commission. Based on the evaluation, as of December 31, 2015 our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective to provide reasonable assurance that the information required to be disclosed in reports that we file or submit under the Exchange Act is accumulated and communicated to management, and made known to our principal executive officer and principal financial officer, on a timely basis to ensure that it is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
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Management’s Annual Report on Internal Control Over Financial Reporting
As required by Exchange Act Rules 13a-15(c) and 15d-15(c), our management, including the Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness as to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Based on the results of management’s evaluation described above, management concluded that our internal control over financial reporting was effective as of December 31, 2015.
The effectiveness of internal control over financial reporting as of December 31, 2015 was audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in its report found within this report.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the last fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Archrock, Inc.
Houston, Texas
We have audited the internal control over financial reporting of Archrock, Inc. and subsidiaries (the “Company”) as of December 31, 2015, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2015 of the Company and our report dated February 29, 2016 expressed an unqualified opinion on those financial statements and financial statement schedule and included an explanatory paragraph regarding the Company’s completed spin-off of its international contract operations, international aftermarket services, and global fabrication businesses into an independent, publicly traded company named Exterran Corporation.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 29, 2016
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Item 9B. Other Information
None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
The information required in Part III, Item 10 of this Annual Report on Form 10-K is incorporated by reference to the sections entitled “Election of Directors,” “Corporate Governance,” “Executive Officers” and “Beneficial Ownership of Common Stock” in our definitive proxy statement, to be filed with the SEC within 120 days of the end of our fiscal year.
Item 11. Executive Compensation
The information required in Part III, Item 11 of this Annual Report on Form 10-K is incorporated by reference to the sections entitled “Compensation Discussion and Analysis” and “Information Regarding Executive Compensation” in our definitive proxy statement, to be filed with the SEC within 120 days of the end of our fiscal year.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Portions of the information required in Part III, Item 12 of this report are incorporated by reference to the section entitled “Beneficial Ownership of Common Stock” in our definitive proxy statement, to be filed with the SEC within 120 days of the end of our fiscal year.
Securities Authorized for Issuance under Equity Compensation Plans
The following table sets forth information as of December 31, 2015, with respect to the Archrock compensation plans under which our common stock is authorized for issuance, aggregated as follows:
Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights | Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights | Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (3) | ||||||||
Plan Category | ||||||||||
Equity compensation plans approved by security holders(1) | 891,388 | $ | 12.66 | 4,761,111 | ||||||
Equity compensation plans not approved by security holders(2) | — | — | 48,022 | |||||||
Total | 891,388 | 0 | 4,809,133 | |||||||
(1) | Comprised of the Archrock, Inc. 2013 Stock Incentive Plan (as amended, the “2013 Plan”), the Archrock, Inc. Amended and Restated 2007 Stock Incentive Plan (as amended, the “2007 Plan”) and the Archrock, Inc. Employee Stock Purchase Plan. In addition to the outstanding options, as of December 31, 2015 there were 40,609 restricted stock units, payable in common stock upon vesting, outstanding under the 2007 Plan and the 2013 Plan which have been deducted from column (c). No additional grants may be made under the 2007 Plan. |
(2) | Comprised of the Archrock, Inc. Directors’ Stock and Deferral Plan. |
(3) | Excludes number of securities to be issued upon exercise of outstanding options, warrants and rights. |
The table above does not include information with respect to an equity plan we assumed from Universal (the “Universal Plan”). No additional grants may be made under the Universal Plan.
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The following equity grants are outstanding under the Universal Plan that was approved by security holders:
Number of Shares Reserved for Issuance Upon the Exercise of Outstanding Stock Options | Weighted- Average Exercise Price | Shares Available for Future Grants | |||||||
Plan Category | |||||||||
Universal Compression Holdings, Inc. Incentive Stock Option Plan | 355,024 | $ | 32.37 | None | |||||
Item 13. Certain Relationships and Related Transactions and Director Independence
The information required in Part III, Item 13 of this Annual Report on Form 10-K is incorporated by reference to the sections entitled “Certain Relationships and Related Transactions” and “Corporate Governance” in our definitive proxy statement, to be filed with the SEC within 120 days of the end of our fiscal year.
Item 14. Principal Accountant Fees and Services
The information required in Part III, Item 14 of this Annual Report on Form 10-K is incorporated by reference to the section entitled “Ratification of the Appointment of Independent Registered Public Accounting Firm” in our definitive proxy statement, to be filed with the SEC within 120 days of the end of our fiscal year.
PART IV
Item 15. Exhibits and Financial Statement Schedules
(a) | Documents filed as a part of this Annual Report on Form 10-K. |
1. | Financial Statements. The following financial statements are filed as a part of this Annual Report on Form 10-K. |
2. | Financial Statement Schedule |
All other schedules have been omitted because they are not required under the relevant instructions.
3. | Exhibits |
Exhibit No. | Description | |
2.1 | Contribution, Conveyance and Assumption Agreement, dated April 17, 2015, by and among Exterran Holdings, Inc., Exterran Energy Solutions, L.P., EES Leasing LLC, EXH GP LP LLC, Exterran GP LLC, EXH MLP LP LLC, Exterran General Partner, L.P., EXLP Operating LLC, EXLP Leasing LLC and Exterran Partners, L.P., incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed on April 20, 2015 | |
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2.2 | Separation and Distribution Agreement, dated as of November 3, 2015, by and among Exterran Holdings, Inc., Exterran General Holdings LLC, Exterran Energy Solutions, L.P., Exterran Corporation, AROC Corp., EESLP LP LLC, AROC Services GP LLC, AROC Services LP LLC and Archrock Services, L.P., incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed on November 5, 2015 | |
2.3* | Amendment No. 1 to Separation and Distribution Agreement, dated as of December 15, 2015, by and among Archrock, Inc., formerly named Exterran Holdings, Inc., Exterran General Holdings LLC, Exterran Energy Solutions, L.P., Exterran Corporation, AROC Corp., EESLP LP LLC, AROC Services GP LLC, AROC Services LP LLC and Archrock Services, L.P. | |
3.1 | Restated Certificate of Incorporation of Exterran Holdings, Inc. (now Archrock, Inc.), incorporated by reference to Exhibit 3.1 of the Registrant’s Current Report on Form 8-K filed on August 20, 2007 | |
3.2 | Certificate of Amendment to Certificate of Incorporation of Exterran Holdings, Inc. (now Archrock, Inc.), incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed on November 5, 2015 | |
3.3* | Composite Restated Certificate of Incorporation of Archrock, Inc. | |
3.4 | Third Amended and Restated Bylaws of Exterran Holdings, Inc. (now Archrock, Inc.), incorporated by reference to Exhibit 3.1 of the Registrant’s Current Report on Form 8-K filed on March 20, 2013 | |
10.1 | Credit Agreement, dated as of July 10, 2015, by and among Exterran Holdings, Inc. (now Archrock, Inc.), Archrock Services, L.P., the lenders from time to time party thereto and Wells Fargo Bank, National Association, as administrative agent, incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on July 16, 2015 | |
10.2 | First Amendment to Credit Agreement, dated as of October 5, 2015, by and among Exterran Holdings, Inc. (now Archrock, Inc.), Archrock Services, L.P., the lenders signatory thereto and Wells Fargo Bank, National Association, as administrative agent, incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed on October 6, 2015 | |
10.3 | Amended and Restated Senior Secured Credit Agreement, dated as of November 3, 2010, by and among EXLP Operating LLC, as Borrower, Exterran Partners, L.P., as Guarantor, Wells Fargo Bank, National Association, as Administrative Agent, Bank of America, N.A. and JPMorgan Chase Bank, N.A., as Co-Syndication Agents, Barclays Bank plc and The Royal Bank of Scotland plc, as Co-Documentation Agents, and the lenders signatory thereto, incorporated by reference to Exhibit 10.1 to Exterran Partners L.P.’s Current Report on Form 8-K filed on November 9, 2010 | |
10.4 | First Amendment to Amended and Restated Senior Secured Credit Agreement, dated March 7, 2012, among EXLP Operating LLC, as Borrower, Exterran Partners, L.P., as Guarantor, Wells Fargo Bank, National Association, as Administrative Agent and Swingline Lender, and the other lenders signatory thereto, incorporated by reference to Exhibit 10.1 to Exterran Partners, L.P.’s Current Report on Form 8-K filed on March 13, 2012 | |
10.5 | Third Amendment to Amended and Restated Senior Secured Credit Agreement, dated March 27, 2013, among EXLP Operating LLC, as Borrower, Exterran Partners, L.P., as Guarantor, Wells Fargo Bank, National Association, as Administrative Agent, and the other lenders signatory thereto, incorporated by reference to Exhibit 10.1 to Exterran Partners, L.P.’s Current Report on Form 8-K filed on March 28, 2013 | |
10.6 | Fourth Amendment to Amended and Restated Senior Secured Credit Agreement, dated February 4, 2015, among EXLP Operating LLC, as Borrower, Exterran Partners, L.P., as Guarantor, Wells Fargo Bank, National Association, as Administrative Agent, and the other lenders signatory thereto, incorporated by reference to Exhibit 10.1 to Exterran Partners, L.P.’s Current Report on Form 8-K filed on February 5, 2015 | |
10.7 | Amended and Restated Guaranty Agreement, dated as of November 3, 2010, made by Exterran Partners, L.P. and EXLP Leasing LLC in favor of Wells Fargo Bank, National Association, as Administrative Agent, incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on November 9, 2010 | |
10.8 | Amended and Restated Collateral Agreement, dated as of November 3, 2010, made by EXLP Operating LLC, Exterran Partners, L.P. and EXLP Leasing LLC in favor of Wells Fargo Bank, National Association, as Administrative Agent, incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed on November 9, 2010 | |
10.9 | Third Amended and Restated Omnibus Agreement, dated June 10, 2011, by and among Exterran Holdings, Inc., Exterran Energy Solutions, L.P., Exterran GP LLC, Exterran General Partner, L.P., EXLP Operating LLC and Exterran Partners, L.P., incorporated by reference to Exhibit 10.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 (portions of this exhibit have been omitted by redacting a portion of the text (indicated by asterisks in the text) and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment) | |
10.10 | First Amendment to Third Amended and Restated Omnibus Agreement, dated March 8, 2012, by and among Exterran Holdings, Inc., Exterran Energy Solutions, L.P., Exterran GP LLC, Exterran General Partner, L.P., EXLP Operating LLC and Exterran Partners, L.P. (portions of this exhibit have been omitted by redacting a portion of the text (indicated by asterisks in the text) and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment), incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2012 | |
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10.11 | Second Amendment to Third Amended and Restated Omnibus Agreement, dated March 31, 2013, by and among Exterran Holdings, Inc., Exterran Energy Solutions, L.P., Exterran GP LLC, Exterran General Partner, L.P., Exterran Partners, L.P. and EXLP Operating LLC (portions of this exhibit have been omitted by redacting a portion of the text (indicated by asterisks in the text) and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment), incorporated by reference to Exhibit 10.1 to the Registrant’s Form 10-Q for the quarter ended March 31, 2013 | |
10.12 | Third Amendment to Third Amended and Restated Omnibus Agreement, dated April 10, 2014, by and among Exterran Holdings, Inc., Exterran Energy Solutions, L.P., Exterran GP LLC, Exterran General Partner, L.P., Exterran Partners, L.P. and EXLP Operating LLC, incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014 | |
10.13 | Fourth Amendment to Third Amended and Restated Omnibus Agreement, dated August 15, 2014, by and among Exterran Holdings, Inc., Exterran Energy Solutions, L.P., Exterran GP LLC, Exterran General Partner, L.P., Exterran Partners, L.P. and EXLP Operating LLC, incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014 (portions of this exhibit have been omitted by redacting a portion of the text (indicated by asterisks in the text) and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment) | |
10.14 | Fifth Amendment to Third Amended and Restated Omnibus Agreement, dated February 23, 2015, by and among Exterran Holdings, Inc., Exterran Energy Solutions, L.P., Exterran GP LLC, Exterran General Partner, L.P., Exterran Partners, L.P. and EXLP Operating LLC | |
10.15 | Sixth Amendment to Third Amended and Restated Omnibus Agreement, dated April 17, 2015, by and among Exterran Holdings, Inc., Exterran Energy Solutions, L.P., Exterran GP LLC, Exterran General Partner, L.P., Exterran Partners, L.P. and EXLP Operating LLC, incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2015 filed on May 5, 2015. | |
10.16* | Fourth Amended and Restated Omnibus Agreement, dated November 3, 2015, by and among Archrock, Inc. (formerly named Exterran Holdings, Inc.), Archrock Services, L.P. (formerly named Exterran US Services OpCo, L.P.), Archrock GP, LLC (formerly named Exterran GP, LLC), Archrock General Partner, L.P. (formerly named Exterran General Partner, L.P.), Archrock Partners, L. P. (formerly named Exterran Partners, L.P.) and Archrock Partners Operating LLC (portions of this exhibit have been omitted by redacting a portion of the text (indicated by asterisks in the text) and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment) | |
10.17† | Exterran Holdings, Inc. (now Archrock, Inc.) 2013 Stock Incentive Plan, incorporated by reference to Annex A to the Registrant’s Definitive Proxy Statement on Schedule 14A filed on March 19, 2013 | |
10.18† | First Amendment to the Exterran Holdings, Inc. (now Archrock, Inc.) 2013 Stock Incentive Plan, incorporated by reference to Exhibit 10.13 to the Registrant’s Current Report on Form 8-K filed on November 5, 2015 | |
10.19† | Exterran Holdings, Inc. (now Archrock, Inc.) Amended and Restated 2007 Stock Incentive Plan, incorporated by reference to Annex B to the Registrant’s Definitive Proxy Statement on Schedule 14A filed on March 26, 2009 | |
10.20† | Amendment No. 1 to Exterran Holdings, Inc. (now Archrock, Inc.) Amended and Restated 2007 Stock Incentive Plan, incorporated by reference to Annex A to the Registrant’s Definitive Proxy Statement on Schedule 14A filed on March 26, 2009 | |
10.21† | Amendment No. 2 to Exterran Holdings, Inc. (now Archrock, Inc.) Amended and Restated 2007 Stock Incentive Plan, incorporated by reference to Exhibit 10.10 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009 | |
10.22† | Amendment No. 3 to the Exterran Holdings, Inc. (now Archrock, Inc.) Amended and Restated 2007 Stock Incentive Plan, incorporated by reference to Annex A to the Registrant’s Definitive Proxy Statement on Schedule 14A filed on March 29, 2010 | |
10.23† | Amendment No. 4 to the Exterran Holdings, Inc. (now Archrock, Inc.) Amended and Restated 2007 Stock Incentive Plan, incorporated by reference to Annex A to the Registrant’s Definitive Proxy Statement on Schedule 14A, filed March 29, 2011 | |
10.24† | Amendment No. 5 to the Exterran Holdings, Inc. (now Archrock, Inc.) Amended and Restated 2007 Stock Incentive Plan, incorporated by reference to Exhibit 10.14 to the Registrant’s Current Report on Form 8-K filed on November 5, 2015 | |
10.25† | Exterran Holdings, Inc. 2011 (now Archrock, Inc.) Employment Inducement Long-Term Equity Plan, incorporated by reference to Exhibit 4.1 to the Registrant’s Registration Statement on Form S-8, filed November 4, 2011 | |
10.26† | Exterran Holdings, Inc. (now Archrock, Inc.) Directors’ Stock and Deferral Plan, incorporated by reference to Exhibit 10.16 of the Registrant’s Current Report on Form 8-K filed on August 23, 2007 | |
10.27† | First Amendment to Exterran Holdings, Inc. (now Archrock, Inc.) Directors’ Stock and Deferral Plan, incorporated by reference to Exhibit 10.22 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2008 | |
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10.28† | Second Amendment to Exterran Holdings, Inc. (now Archrock, Inc.) Directors’ Stock and Deferral Plan, incorporated by reference to Exhibit 10.16 to the Registrant’s Current Report on Form 8-K filed on November 5, 2015 | |
10.29† | Exterran Holdings, Inc. (now Archrock, Inc.) Employee Stock Purchase Plan, incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed on August 23, 2007 | |
10.30† | Amendment No. 1 to the Exterran Holdings, Inc. (now Archrock, Inc.) Employee Stock Purchase Plan, incorporated by reference to Annex D to the Registrant’s Definitive Proxy Statement on Schedule 14A, filed March 29, 2011 | |
10.31† | Amendment No. 2 to the Exterran Holdings, Inc. (now Archrock, Inc.) Employee Stock Purchase Plan, incorporated by reference to Annex C to the Registrant’s Definitive Proxy Statement on Schedule 14A, filed March 29, 2011 | |
10.32† | Amendment No. 3 to the Exterran Holdings, Inc. (now Archrock, Inc.) Employee Stock Purchase Plan, incorporated by reference to Exhibit 10.15 to the Registrant’s Current Report on Form 8-K filed on November 5, 2015 | |
10.33† | Archrock Deferred Compensation Plan, incorporated by reference to Exhibit 10.17 to the Registrant’s Current Report on Form 8-K filed on November 5, 2015 | |
10.34† | Exterran (now Archrock, Inc.) Employees’ Supplemental Savings Plan, incorporated by reference to Exhibit 10.30 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2007 | |
10.35† | Form of Exterran Holdings, Inc. (now Archrock, Inc.) Award Notice for Time-Vested Incentive Stock Option, incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009 | |
10.36† | Form of Exterran Holdings, Inc. (now Archrock, Inc.) Award Notice for Time-Vested Non-Qualified Stock Option, incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009 | |
10.37† | Form of Exterran Holdings, Inc. (now Archrock, Inc.) Award Notice for Time-Vested Stock Option for Officers, incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010 | |
10.38† | Form of Exterran Holdings, Inc. (now Archrock, Inc.) Award Notice for Time-Vested Non-Qualified Stock Option, incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010 | |
10.39† | Form of Exterran Holdings, Inc. (now Archrock, Inc.) Award Notice for Time-Vested Stock Option for Officers, incorporated by reference to Exhibit 10.63 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2010 | |
10.40† | Form of Exterran Holdings, Inc. (now Archrock, Inc.) Award Notice for Time-Vested Non-Qualified Stock Option, incorporated by reference to Exhibit 10.64 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2010 | |
10.41† | Form of Indemnification Agreement, incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K filed on August 23, 2007 | |
10.42† | Form of Exterran Holdings, Inc. (now Archrock, Inc.) Award Notice and Agreement for Time-Vested Incentive Stock Option for Officers, incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on March 10, 2014 | |
10.43† | Form of Exterran Holdings, Inc. (now Archrock, Inc.) Award Notice and Agreement for Time-Vested Non-Qualified Stock Option, incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on March 10, 2014 | |
10.44† | Form of Exterran Holdings, Inc. (now Archrock, Inc.) Award Notice and Agreement for Time-Vested Restricted Stock, incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed on March 10, 2014 | |
10.45† | Form of Exterran Holdings, Inc. (now Archrock, Inc.) Award Notice and Agreement for Time-Vested Cash-Settled Restricted Stock Units, incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed on March 10, 2014 | |
10.46† | Form of Exterran Holdings, Inc. (now Archrock, Inc.) Award Notice and Agreement for Time-Vested Stock-Settled Restricted Stock Units, incorporated by reference to Exhibit 10.5 to the Registrant’s Current Report on Form 8-K filed on March 10, 2014 | |
10.47† | Form of Exterran Holdings, Inc. (now Archrock, Inc.) Award Notice and Agreement for Performance Units, incorporated by reference to Exhibit 10.6 to the Registrant’s Current Report on Form 8-K filed on March 10, 2014 | |
10.48† | Form of Exterran Holdings, Inc. (now Archrock, Inc.) Award Notice and Agreement for Common Stock Award for Non-Employee Directors, incorporated by reference to Exhibit 10.7 to the Registrant’s Current Report on Form 8-K filed on March 10, 2014 | |
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10.49† | Form of Exterran Holdings, Inc. (now Archrock, Inc.) Award Notice and Agreement for Performance Units incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on February 25, 2015 | |
10.50*† | Summary of Donna A. Henderson Compensation Arrangement | |
10.51*† | Summary of Jason Ingersoll Compensation Arrangement | |
10.52† | Form of Indemnification Agreement, incorporated by reference to Exhibit 10.7 to the Registrant’s Current Report on Form 8-K filed on November 5, 2015 | |
10.53† | Form of Employment Letter applicable to Messrs. Childers, Miller, Rice, Wayne and Ingersoll, incorporated by reference to Exhibit 10.8 to the Registrant’s Current Report on Form 8-K filed on November 5, 2015 | |
10.54† | Form of Severance Benefit Agreement applicable to Messrs. Childers, Miller, Rice, Wayne and Ingersoll, incorporated by reference to Exhibit 10.9 to the Registrant’s Current Report on Form 8-K filed on November 5, 2015 | |
10.55† | Form of Change of Control Agreement applicable to Messrs. Childers, Miller, Rice, Wayne and Ingersoll, incorporated by reference to Exhibit 10.10 to the Registrant’s Current Report on Form 8-K filed on November 5, 2015 | |
10.56† | Form of Award Notice and Agreement for Restricted Stock pursuant to the 2013 Stock Incentive Plan, incorporated by reference to Exhibit 10.11 to the Registrant’s Current Report on Form 8-K filed on November 5, 2015 | |
10.57† | Form of Award Notice and Agreement for Common Stock Award for Non-Employee Directors pursuant to the 2013 Stock Incentive Plan, incorporated by reference to Exhibit 10.12 to the Registrant’s Current Report on Form 8-K filed on November 5, 2015 | |
10.58† | Form of Archrock, Inc. Award Notice and Agreement for Performance Units, incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on February 24, 2016 | |
10.59† | Form of Archrock, Inc. Award Notice and Agreement for Time-Vested Restricted Stock, incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on February 24, 2016 | |
10.60† | Form of Archrock, Inc. Award Notice and Agreement for Time-Vested Stock-Settled Restricted Stock Units, incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed on February 24, 2016 | |
10.61† | Form of Archrock, Inc. Award Notice and Agreement for Common Stock Award for Non-Employee Directors, incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed on February 24, 2016 | |
10.62 | Employee Matters Agreement, dated as of November 3, 2015, by and between Exterran Holdings, Inc. (now Archrock, Inc.) and Exterran Corporation, incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on November 5, 2015 | |
10.63 | Tax Matters Agreement, dated as of November 3, 2015, by and between Exterran Holdings, Inc. (now Archrock, Inc.) and Exterran Corporation, incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on November 5, 2015 | |
10.64 | Transition Services Agreement, dated as of November 3, 2015, by and between Exterran Holdings, Inc. (now Archrock, Inc.) and Exterran Corporation, incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed on November 5, 2015 | |
10.65 | Supply Agreement, dated as of November 3, 2015, by and among Archrock Services, L.P., EXLP Operating LLC and Exterran Energy Solutions, L.P., incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed on November 5, 2015 | |
21.1* | List of Subsidiaries of Archrock, Inc. | |
23.1* | Consent of Deloitte & Touche LLP | |
31.1* | Certification of the Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |
31.2* | Certification of the Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |
32.1** | Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | |
32.2** | Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | |
101.1* | Interactive data files pursuant to Rule 405 of Regulation S-T | |
† Management contract or compensatory plan or arrangement.
* Filed herewith.
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** Furnished, not filed.
74
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Archrock, Inc. | |
/s/ D. BRADLEY CHILDERS | |
Name: D. Bradley Childers | |
Title: President and Chief Executive Officer | |
Date: February 29, 2016 | |
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POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints D. Bradley Childers, David S. Miller, Donna A. Henderson and Donald C. Wayne, and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Report, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done as fully to all said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue thereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on February 29, 2016.
Signature | Title | |
/s/ D. BRADLEY CHILDERS | President and Chief Executive Officer and Director | |
D. Bradley Childers | (Principal Executive Officer) | |
/s/ DAVID S. MILLER | Senior Vice President and Chief Financial | |
David S. Miller | Officer (Principal Financial Officer) | |
/s/ DONNA A. HENDERSON | Vice President and Chief Accounting Officer | |
Donna A. Henderson | (Principal Accounting Officer) | |
/s/ ANNIE-MARIE N. AINSWORTH | Director | |
Annie-Marie N. Ainsworth | ||
/s/ WENDELL R. BROOKS | Director | |
Wendell R. Brooks | ||
/s/ GORDON T. HALL | Director | |
Gordon T. Hall | ||
/s/ FRANCES P. HAWES | Director | |
Frances P. Hawes | ||
/s/ J.W.G. HONEYBOURNE | Director | |
J.W.G. Honeybourne | ||
/s/ JAMES H. LYTAL | Director | |
James H. Lytal | ||
/s/ MARK A. MCCOLLUM | Director | |
Mark A. McCollum | ||
76
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Archrock, Inc.
Houston, Texas
We have audited the accompanying consolidated balance sheets of Archrock, Inc. and subsidiaries (the “Company”) as of December 31, 2015 and 2014, and the related consolidated statements of operations, comprehensive income (loss), equity, and cash flows for each of the three years in the period ended December 31, 2015. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
As discussed in Note 2 to the consolidated financial statements, on November 3, 2015, the Company completed the spin-off of its international contract operations, international aftermarket services, and global fabrication businesses into an independent, publicly traded company named Exterran Corporation.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2015, based on the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 29, 2016 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 29, 2016
F-1
ARCHROCK, INC.
CONSOLIDATED BALANCE SHEETS
(In thousands, except par value and share amounts)
December 31, | |||||||
2015 | 2014 | ||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 1,563 | $ | 378 | |||
Accounts receivable, net of allowance of $3,343 and $2,286, respectively | 147,786 | 159,972 | |||||
Inventory | 129,411 | 145,786 | |||||
Other current assets | 6,123 | 7,526 | |||||
Current assets associated with discontinued operations | 420 | 872,158 | |||||
Total current assets | 285,303 | 1,185,820 | |||||
Property, plant and equipment, net | 2,267,788 | 2,372,081 | |||||
Goodwill | — | 3,738 | |||||
Intangible and other assets, net | 132,472 | 154,153 | |||||
Long-term assets associated with discontinued operations | 21,200 | 1,211,047 | |||||
Total assets | $ | 2,706,763 | $ | 4,926,839 | |||
LIABILITIES AND EQUITY | |||||||
Current liabilities: | |||||||
Accounts payable, trade | $ | 52,430 | $ | 41,480 | |||
Accrued liabilities | 80,053 | 91,182 | |||||
Deferred revenue | 2,201 | 4,490 | |||||
Current liabilities associated with discontinued operations | 420 | 472,931 | |||||
Total current liabilities | 135,104 | 610,083 | |||||
Long-term debt | 1,588,465 | 2,025,795 | |||||
Deferred income taxes | 178,566 | 218,672 | |||||
Other long-term liabilities | 11,655 | 10,161 | |||||
Long-term liabilities associated with discontinued operations | 5,714 | 109,083 | |||||
Total liabilities | 1,919,504 | 2,973,794 | |||||
Commitments and contingencies (Note 20) | |||||||
Equity: | |||||||
Preferred stock, $0.01 par value per share; 50,000,000 shares authorized; zero issued | — | — | |||||
Common stock, $0.01 par value per share; 250,000,000 shares authorized; 75,014,308 and 73,808,200 shares issued, respectively | 750 | 738 | |||||
Additional paid-in capital | 2,820,958 | 3,715,586 | |||||
Accumulated other comprehensive income (loss) | (1,570 | ) | 15,865 | ||||
Accumulated deficit | (2,013,799 | ) | (1,866,397 | ) | |||
Treasury stock — 5,383,970 and 4,963,013 common shares, at cost, respectively | (72,429 | ) | (68,532 | ) | |||
Total Archrock stockholders’ equity | 733,910 | 1,797,260 | |||||
Noncontrolling interest | 53,349 | 155,785 | |||||
Total equity | 787,259 | 1,953,045 | |||||
Total liabilities and equity | $ | 2,706,763 | $ | 4,926,839 | |||
The accompanying notes are an integral part of these consolidated financial statements.
F-2
ARCHROCK, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
Years Ended December 31, | |||||||||||
2015 | 2014 | 2013 | |||||||||
Revenues: | |||||||||||
Contract operations | $ | 781,166 | $ | 729,103 | $ | 627,844 | |||||
Aftermarket services | 216,942 | 230,050 | 234,928 | ||||||||
998,108 | 959,153 | 862,772 | |||||||||
Costs and expenses: | |||||||||||
Cost of sales (excluding depreciation and amortization expense): | |||||||||||
Contract operations | 319,401 | 316,142 | 282,489 | ||||||||
Aftermarket services | 175,645 | 188,251 | 188,489 | ||||||||
Selling, general and administrative | 131,919 | 132,651 | 118,851 | ||||||||
Depreciation and amortization | 229,127 | 212,268 | 187,476 | ||||||||
Long-lived asset impairment | 124,979 | 42,828 | 16,696 | ||||||||
Restructuring and other charges | 4,745 | 5,394 | — | ||||||||
Goodwill impairment | 3,738 | — | — | ||||||||
Interest expense | 107,617 | 112,273 | 112,194 | ||||||||
Debt extinguishment costs | 9,201 | — | — | ||||||||
Other (income) expense, net | (2,079 | ) | (5,475 | ) | (22,535 | ) | |||||
1,104,293 | 1,004,332 | 883,660 | |||||||||
Loss before income taxes | (106,185 | ) | (45,179 | ) | (20,888 | ) | |||||
Provision for (benefit from) income taxes | 53,189 | (28,066 | ) | (17,840 | ) | ||||||
Loss from continuing operations | (159,374 | ) | (17,113 | ) | (3,048 | ) | |||||
Income from discontinued operations, net of tax | 60,408 | 142,995 | 158,790 | ||||||||
Net income (loss) | (98,966 | ) | 125,882 | 155,742 | |||||||
Less: Net income attributable to the noncontrolling interest | (6,852 | ) | (27,716 | ) | (32,578 | ) | |||||
Net income (loss) attributable to Archrock stockholders | $ | (105,818 | ) | $ | 98,166 | $ | 123,164 | ||||
Basic income (loss) per common share: | |||||||||||
Loss from continuing operations attributable to Archrock common stockholders | $ | (2.44 | ) | $ | (0.68 | ) | $ | (0.55 | ) | ||
Income from discontinued operations attributable to Archrock common stockholders | 0.89 | 2.15 | 2.46 | ||||||||
Net income (loss) attributable to Archrock common stockholders | $ | (1.55 | ) | $ | 1.47 | $ | 1.91 | ||||
Diluted income (loss) per common share: | |||||||||||
Loss from continuing operations attributable to Archrock common stockholders | $ | (2.44 | ) | $ | (0.68 | ) | $ | (0.55 | ) | ||
Income from discontinued operations attributable to Archrock common stockholders | 0.89 | 2.15 | 2.46 | ||||||||
Net income (loss) attributable to Archrock common stockholders | $ | (1.55 | ) | $ | 1.47 | $ | 1.91 | ||||
Weighted average common shares outstanding used in income (loss) per common share: | |||||||||||
Basic | 68,433 | 66,234 | 64,454 | ||||||||
Diluted | 68,433 | 66,234 | 64,454 | ||||||||
Dividends declared and paid per common share | $ | 0.60 | $ | 0.60 | $ | — | |||||
The accompanying notes are an integral part of these consolidated financial statements.
F-3
ARCHROCK, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
Years Ended December 31, | |||||||||||
2015 | 2014 | 2013 | |||||||||
Net income (loss) | $ | (98,966 | ) | $ | 125,882 | $ | 155,742 | ||||
Other comprehensive income (loss), net of tax: | |||||||||||
Derivative gain (loss), net of reclassifications to earnings | (3,465 | ) | (3,366 | ) | 5,207 | ||||||
Adjustments from changes in ownership of Partnership | (223 | ) | 65 | (703 | ) | ||||||
Amortization of terminated interest rate swaps | 1,990 | 2,944 | 2,713 | ||||||||
Foreign currency translation adjustment | (16,776 | ) | (14,648 | ) | 4,531 | ||||||
Total other comprehensive income (loss) | (18,474 | ) | (15,005 | ) | 11,748 | ||||||
Comprehensive income (loss) | (117,440 | ) | 110,877 | 167,490 | |||||||
Less: Comprehensive income attributable to the noncontrolling interest | (5,813 | ) | (26,924 | ) | (38,157 | ) | |||||
Comprehensive income (loss) attributable to Archrock stockholders | $ | (123,253 | ) | $ | 83,953 | $ | 129,333 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
F-4
ARCHROCK, INC.
CONSOLIDATED STATEMENTS OF EQUITY
(In thousands, except share data)
Archrock, Inc. Stockholders | |||||||||||||||||||||||||||||||||
Common Stock | Additional Paid-in Capital | Accumulated Other Comprehensive Income(Loss) | Treasury Stock | Accumulated Deficit | Noncontrolling Interest | ||||||||||||||||||||||||||||
Shares | Amount | Shares | Amount | Total | |||||||||||||||||||||||||||||
Balance, January 1, 2013 | 71,291,230 | $ | 713 | $ | 3,710,758 | $ | 23,909 | (6,376,426 | ) | $ | (209,359 | ) | $ | (2,047,408 | ) | $ | 223,646 | $ | 1,702,259 | ||||||||||||||
Treasury stock purchased | (173,267 | ) | (4,539 | ) | (4,539 | ) | |||||||||||||||||||||||||||
Options exercised | 459,416 | 4 | 8,317 | 8,321 | |||||||||||||||||||||||||||||
Shares issued in employee stock purchase plan | 66,259 | 1 | 1,631 | 1,632 | |||||||||||||||||||||||||||||
Stock-based compensation, net of forfeitures | 683,868 | 7 | 15,509 | (32,375 | ) | 732 | 16,248 | ||||||||||||||||||||||||||
Income tax benefit from stock-based compensation expense | 1,782 | 1,782 | |||||||||||||||||||||||||||||||
Adjustments from changes in ownership of Partnership | 31,573 | (49,238 | ) | (17,665 | ) | ||||||||||||||||||||||||||||
Cash distribution to noncontrolling unitholders of the Partnership | (61,959 | ) | (61,959 | ) | |||||||||||||||||||||||||||||
Other | (141 | ) | (141 | ) | |||||||||||||||||||||||||||||
Comprehensive income (loss): | |||||||||||||||||||||||||||||||||
Net income | 123,164 | 32,578 | 155,742 | ||||||||||||||||||||||||||||||
Derivatives gain (loss), net of reclassifications to earnings and tax | (372 | ) | 5,579 | 5,207 | |||||||||||||||||||||||||||||
Adjustments from changes in ownership of Partnership | (703 | ) | (703 | ) | |||||||||||||||||||||||||||||
Amortization of terminated interest rate swaps, net of tax | 2,713 | 2,713 | |||||||||||||||||||||||||||||||
Foreign currency translation adjustment | 4,531 | 4,531 | |||||||||||||||||||||||||||||||
Balance at December 31, 2013 | 72,500,773 | $ | 725 | $ | 3,769,429 | $ | 30,078 | (6,582,068 | ) | $ | (213,898 | ) | $ | (1,924,244 | ) | $ | 151,338 | $ | 1,813,428 | ||||||||||||||
Treasury stock purchased | (172,232 | ) | (7,044 | ) | (7,044 | ) | |||||||||||||||||||||||||||
Options exercised | 729,685 | 7 | 12,812 | 12,819 | |||||||||||||||||||||||||||||
Cash dividends | (40,319 | ) | (40,319 | ) | |||||||||||||||||||||||||||||
Shares issued in employee stock purchase plan | 50,232 | 1,812 | 1,812 | ||||||||||||||||||||||||||||||
Stock-based compensation, net of forfeitures | 466,011 | 5 | 17,844 | (42,213 | ) | 1,167 | 19,016 | ||||||||||||||||||||||||||
Income tax benefit from stock-based compensation expense | 6,586 | 6,586 | |||||||||||||||||||||||||||||||
Net proceeds from the sale of Partnership units, net of tax | 74,521 | 51,212 | 125,733 | ||||||||||||||||||||||||||||||
Cash distribution to noncontrolling unitholders of the Partnership | (74,856 | ) | (74,856 | ) | |||||||||||||||||||||||||||||
Redemption of convertible debt | 61,499 | 1 | (234,219 | ) | 6,711,587 | 219,211 | (15,007 | ) | |||||||||||||||||||||||||
Shares acquired from exercise of call options | 89,407 | (6,522,301 | ) | (89,407 | ) | — | |||||||||||||||||||||||||||
Shares issued for exercise of warrants | (22,606 | ) | 1,644,214 | 22,606 | — | ||||||||||||||||||||||||||||
Comprehensive income (loss): | |||||||||||||||||||||||||||||||||
Net income | 98,166 | 27,716 | 125,882 | ||||||||||||||||||||||||||||||
Derivatives loss, net of reclassifications to earnings and tax | (2,574 | ) | (792 | ) | (3,366 | ) | |||||||||||||||||||||||||||
Adjustments from changes in ownership of Partnership | 65 | 65 | |||||||||||||||||||||||||||||||
Amortization of terminated interest rate swaps, net of tax | 2,944 | 2,944 | |||||||||||||||||||||||||||||||
Foreign currency translation adjustment | (14,648 | ) | (14,648 | ) | |||||||||||||||||||||||||||||
Balance at December 31, 2014 | 73,808,200 | $ | 738 | $ | 3,715,586 | $ | 15,865 | (4,963,013 | ) | $ | (68,532 | ) | $ | (1,866,397 | ) | $ | 155,785 | $ | 1,953,045 | ||||||||||||||
Treasury stock purchased | (137,994 | ) | (3,985 | ) | (3,985 | ) | |||||||||||||||||||||||||||
Options exercised | 89,759 | 1 | 1,105 | 1,106 | |||||||||||||||||||||||||||||
Cash dividends | (41,584 | ) | (41,584 | ) | |||||||||||||||||||||||||||||
Shares issued in employee stock purchase plan | 28,693 | 910 | 910 | ||||||||||||||||||||||||||||||
Stock-based compensation, net of forfeitures | 1,087,656 | 11 | 16,473 | (289,335 | ) | 1,164 | 17,648 | ||||||||||||||||||||||||||
Income tax expense from stock-based compensation expense | (478 | ) | (478 | ) | |||||||||||||||||||||||||||||
Adjustments from changes in ownership of Partnership | 17,662 | (27,634 | ) | (9,972 | ) | ||||||||||||||||||||||||||||
Net proceeds from the sale of Partnership units, net of tax | 724 | 724 | |||||||||||||||||||||||||||||||
Cash distribution to noncontrolling unitholders of the Partnership | (81,779 | ) | (81,779 | ) | |||||||||||||||||||||||||||||
Shares issued for exercise of warrants | (88 | ) | 6,372 | 88 | — | ||||||||||||||||||||||||||||
Spin-off of Exterran Corporation | (930,936 | ) | (13,218 | ) | (944,154 | ) | |||||||||||||||||||||||||||
Comprehensive income (loss): | |||||||||||||||||||||||||||||||||
Net income (loss) | (105,818 | ) | 6,852 | (98,966 | ) | ||||||||||||||||||||||||||||
Derivatives loss, net of reclassifications to earnings and tax | (2,426 | ) | (1,039 | ) | (3,465 | ) | |||||||||||||||||||||||||||
Adjustments from changes in ownership of Partnership | (223 | ) | (223 | ) | |||||||||||||||||||||||||||||
Amortization of terminated interest rate swaps, net of tax | 1,990 | 1,990 | |||||||||||||||||||||||||||||||
Foreign currency translation adjustment | (3,558 | ) | (3,558 | ) | |||||||||||||||||||||||||||||
Balance at December 31, 2015 | 75,014,308 | $ | 750 | $ | 2,820,958 | $ | (1,570 | ) | (5,383,970 | ) | $ | (72,429 | ) | $ | (2,013,799 | ) | $ | 53,349 | $ | 787,259 | |||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-5
ARCHROCK, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Years Ended December 31, | |||||||||||
2015 | 2014 | 2013 | |||||||||
Cash flows from operating activities: | |||||||||||
Net income (loss) | $ | (98,966 | ) | $ | 125,882 | $ | 155,742 | ||||
Adjustments to reconcile net income (loss) to cash provided by operating activities: | |||||||||||
Depreciation and amortization | 229,127 | 212,268 | 187,476 | ||||||||
Long-lived asset impairment | 124,979 | 42,828 | 16,696 | ||||||||
Goodwill impairment | 3,738 | — | — | ||||||||
Amortization of deferred financing costs | 6,429 | 5,994 | 7,690 | ||||||||
Debt extinguishment costs | 9,201 | — | — | ||||||||
Income from discontinued operations, net of tax | (60,408 | ) | (142,995 | ) | (158,790 | ) | |||||
Amortization of debt discount | 1,170 | 12,380 | 23,407 | ||||||||
Provision for doubtful accounts | 3,163 | 1,824 | 494 | ||||||||
Gain on sale of property, plant and equipment | (1,645 | ) | (5,645 | ) | (24,035 | ) | |||||
Amortization of terminated interest rate swaps | 3,063 | 4,530 | 4,174 | ||||||||
Interest rate swaps | 603 | 397 | 334 | ||||||||
Stock-based compensation expense | 10,029 | 8,998 | 6,418 | ||||||||
Non-cash restructuring charges | 2,515 | 4,103 | — | ||||||||
Deferred income tax provision | 49,991 | (33,586 | ) | (19,437 | ) | ||||||
Changes in assets and liabilities, net of acquisitions: | |||||||||||
Accounts receivable and notes | 9,023 | (37,109 | ) | (13,755 | ) | ||||||
Inventory | 16,276 | 29,640 | (29,941 | ) | |||||||
Other current assets | 1,242 | (3,801 | ) | 692 | |||||||
Accounts payable and other liabilities | (626 | ) | (606 | ) | (34,607 | ) | |||||
Deferred revenue | (2,401 | ) | (1,099 | ) | (2,104 | ) | |||||
Other | 15,971 | (7,986 | ) | (356 | ) | ||||||
Net cash provided by continuing operations | 322,474 | 216,017 | 120,098 | ||||||||
Net cash provided by discontinued operations | 105,106 | 163,353 | 235,605 | ||||||||
Net cash provided by operating activities | 427,580 | 379,370 | 355,703 | ||||||||
Cash flows from investing activities: | |||||||||||
Capital expenditures | (256,142 | ) | (383,841 | ) | (291,530 | ) | |||||
Proceeds from sale of property, plant and equipment | 18,767 | 12,154 | 80,047 | ||||||||
Payments for business acquisitions | — | (494,755 | ) | — | |||||||
Net cash used in continuing operations | (237,375 | ) | (866,442 | ) | (211,483 | ) | |||||
Net cash provided by (used in) discontinued operations | (91,504 | ) | (63,409 | ) | 15,032 | ||||||
Net cash used in investing activities | (328,879 | ) | (929,851 | ) | (196,451 | ) | |||||
Cash flows from financing activities: | |||||||||||
Proceeds from borrowings of long-term debt | 1,483,258 | 2,240,299 | 2,108,037 | ||||||||
Repayments of long-term debt | (1,921,758 | ) | (1,727,500 | ) | (2,195,750 | ) | |||||
Payments for debt issuance costs | (6,100 | ) | (6,986 | ) | (12,147 | ) | |||||
Payments above face value for redemption of convertible debt | — | (15,007 | ) | — | |||||||
Payments above face value for redemption of senior notes | (6,346 | ) | — | — | |||||||
Payments for settlement of interest rate swaps that include financing elements | (3,728 | ) | (3,793 | ) | (2,207 | ) | |||||
Net proceeds from the sale of Partnership units | 1,164 | 169,471 | — | ||||||||
Proceeds from stock options exercised | 1,106 | 12,819 | 8,321 | ||||||||
Proceeds from stock issued pursuant to our employee stock purchase plan | 910 | 1,812 | 1,632 | ||||||||
Purchases of treasury stock | (3,985 | ) | (7,044 | ) | (4,539 | ) | |||||
Dividends to Archrock stockholders | (41,584 | ) | (40,319 | ) | — | ||||||
Stock-based compensation excess tax benefit | 1,227 | 6,151 | 969 | ||||||||
Special distribution from Exterran Corporation | 532,578 | — | — | ||||||||
Cash distributed to Exterran Corporation | (52,479 | ) | — | — | |||||||
Distributions to noncontrolling partners in the Partnership | (81,779 | ) | (74,856 | ) | (61,959 | ) | |||||
Net cash provided by (used in) continuing operations | (97,516 | ) | 555,047 | (157,643 | ) | ||||||
Net cash provided by discontinued operations | — | 3,434 | 941 | ||||||||
Net cash provided by (used in) financing activities | (97,516 | ) | 558,481 | (156,702 | ) | ||||||
Effect of exchange rate changes on cash and cash equivalents | — | (3,925 | ) | (1,487 | ) | ||||||
Net increase in cash and cash equivalents - total operations | 1,185 | 4,075 | 1,063 | ||||||||
Less: Net increase in cash and cash equivalents - discontinued operations | — | 4,168 | 1,026 | ||||||||
Cash and cash equivalents at beginning of period | 378 | 471 | 434 | ||||||||
Cash and cash equivalents at end of period | $ | 1,563 | $ | 378 | $ | 471 | |||||
Supplemental disclosure of cash flow information: | |||||||||||
Interest paid, net of capitalized amounts | $ | 101,728 | $ | 87,407 | $ | 78,548 | |||||
Income taxes paid, net | $ | 2,057 | $ | 521 | $ | 1,139 | |||||
Supplemental disclosure of non-cash transactions: | |||||||||||
Accrued capital expenditures | $ | 253 | $ | 16,568 | $ | 6,919 | |||||
Treasury shares issued for redemption of convertible debt | $ | — | $ | 219,211 | $ | — | |||||
Shares acquired from exercise of call options | $ | — | $ | (89,407 | ) | $ | — | ||||
Treasury shares issued for exercise of warrants | $ | 88 | $ | 22,606 | $ | — | |||||
Spin-off of Exterran Corporation | $ | (13,218 | ) | $ | — | $ | — | ||||
The accompanying notes are an integral part of these consolidated financial statements.
F-6
ARCHROCK, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Summary of Significant Accounting Policies
Archrock, Inc., formerly Exterran Holdings, Inc., together with its subsidiaries (“Archrock”, “our”, “we”, or “us”) is a pure play United States of America (“U.S.”) natural gas contract operations services business and the leading provider of natural gas compression services to customers in the oil and natural gas industry throughout the U.S. and a leading supplier of aftermarket services to customers that own compression equipment in the U.S. We operate in two primary business lines: contract operations and aftermarket services. In our contract operations business line, we use our fleet of natural gas compression equipment to provide operations services to our customers. In our aftermarket services business line, we sell parts and components and provide operations, maintenance, overhaul and reconfiguration services to customers who own compression equipment.
Principles of Consolidation
The accompanying consolidated financial statements include Archrock and its wholly-owned and majority-owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation. Certain prior year amounts have been reclassified to conform to the current year presentation.
For financial reporting purposes, we consolidate the financial statements of Archrock Partners, L.P. (together with its subsidiaries, the “Partnership”) with those of our own and reflect its operations in our contract operations business segment. We control the Partnership through our ownership of its general partner. Public ownership of the Partnership’s net assets and earnings is presented as a component of noncontrolling interest in our consolidated financial statements. The borrowings of the Partnership are presented as part of our consolidated debt. However, we do not have any obligation for the payment of interest or repayment of borrowings incurred by the Partnership.
Use of Estimates in the Consolidated Financial Statements
The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the U.S. (“GAAP”) requires management to make estimates and assumptions that affect the reported amount of assets, liabilities, revenue and expenses, as well as the disclosures of contingent assets and liabilities. Because of the inherent uncertainties in this process, actual future results could differ from those expected at the reporting date. Management believes that the estimates and assumptions used are reasonable.
Cash and Cash Equivalents
We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
Revenue Recognition
Contract operations revenue is recognized when earned, which generally occurs monthly when service is provided under our customer contracts. Aftermarket services revenue is recognized as products are delivered and title is transferred or services are performed for the customer.
Concentrations of Credit Risk
Financial instruments that potentially subject us to concentrations of credit risk consist of cash and cash equivalents and accounts receivable. We believe that the credit risk in temporary cash investments is limited because our cash is held in accounts with multiple financial institutions. Trade accounts receivable are due from companies of varying size engaged principally in oil and natural gas activities throughout the U.S. We review the financial condition of customers prior to extending credit and generally do not obtain collateral for trade receivables. Payment terms are on a short-term basis and in accordance with industry practice. We consider this credit risk to be limited due to these companies’ financial resources, the nature of products and services we provide and the terms of our contract operations customer service agreements.
F-7
We maintain allowances for doubtful accounts for estimated losses resulting from our customers’ inability to make required payments. The determination of the collectability of amounts due from our customers requires us to use estimates and make judgments regarding future events and trends, including monitoring our customers’ payment history and current creditworthiness to determine that collectability is reasonably assured, as well as consideration of the overall business climate in which our customers operate. Inherently, these uncertainties require us to make judgments and estimates regarding our customers’ ability to pay amounts due to us in order to determine the appropriate amount of valuation allowances required for doubtful accounts. We review the adequacy of our allowance for doubtful accounts quarterly. We determine the allowance needed based on historical write-off experience and by evaluating significant balances aged greater than 90 days individually for collectability. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. During the years ended December 31, 2015, 2014 and 2013, we recorded bad debt expense of $3.1 million, $1.7 million and a recovery of bad debt expense of $0.2 million, respectively.
Inventory
Inventory consists of parts used for maintenance of natural gas compression equipment. Inventory is stated at the lower of cost or market using the average-cost method. A reserve is recorded against inventory balances for estimated obsolescence based on specific identification and historical experience.
Property, Plant and Equipment
Property, plant and equipment are recorded at cost and depreciated using the straight-line method over their estimated useful lives as follows:
Compression equipment, facilities and other fleet assets | 3 to 30 years |
Buildings | 20 to 35 years |
Transportation, shop equipment and other | 3 to 10 years |
Major improvements that extend the useful life of an asset are capitalized. Repairs and maintenance are expensed as incurred. When property, plant and equipment is sold, retired or otherwise disposed of, the gain or loss is recorded in other (income) expense, net. Interest is capitalized during the construction period on equipment and facilities that are constructed for use in our operations. The capitalized interest is included as part of the cost of the asset to which it relates and is amortized over the asset’s estimated useful life.
Computer software
Certain costs related to the development or purchase of internal-use software are capitalized and amortized over the estimated useful life of the software, which ranges from three to five years. Costs related to the preliminary project stage and the post-implementation/operation stage of an internal-use computer software development project are expensed as incurred.
Long-Lived Assets
We review long-lived assets, including property, plant and equipment and identifiable intangibles that are being amortized, for impairment whenever events or changes in circumstances, including the removal of compressor units from our active fleet, indicate that the carrying amount of an asset may not be recoverable. An impairment loss exists when estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount. When necessary, an impairment loss is recognized and represents the excess of the asset’s carrying value as compared to its estimated fair value and is charged to the period in which the impairment occurred. Identifiable intangibles are amortized over the assets’ estimated useful lives.
Goodwill
Goodwill acquired in connection with business combinations represents the excess of consideration over the fair value of tangible and identifiable intangible net assets acquired. Certain assumptions and estimates are employed in determining the fair value of assets acquired and liabilities assumed, as well as in determining the allocation of goodwill to the appropriate reporting unit.
F-8
We review the carrying value of our goodwill for potential impairment in the fourth quarter of every year, or whenever events or other circumstances indicate that we may not be able to recover the carrying amount. We first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. We may elect to perform the two-step goodwill impairment test without completing a qualitative assessment.
If a two-step process goodwill impairment test is elected or required, the first step is to compare the implied fair value of our reporting unit with its carrying value (including the goodwill). If the implied fair value of the reporting unit is higher than the carrying value, no impairment is deemed to exist and no further testing is required. If, however, the implied fair value of the reporting unit is below the recorded carrying value, then a second step must be performed to determine the goodwill impairment required, if any. We calculate the implied fair value of the reporting unit goodwill by allocating the estimated fair value of the reporting unit to all of the assets and liabilities of the reporting unit as if the reporting unit had been acquired in a business combination. If the carrying value of the reporting unit’s goodwill exceeds the implied fair value of the goodwill, we recognize an impairment loss for that excess amount.
Determining the fair value of a reporting unit under the first step of the goodwill impairment test is judgmental in nature and involves the use of significant estimates and assumptions, which have a significant impact on the fair value determined. We determine the fair value of our reporting unit using both the expected present value of future cash flows and a market approach. Each approach is weighted 50% in determining our calculated fair value. The present value of future cash flows is estimated using our most recent forecast and the weighted average cost of capital. The market approach uses a market multiple on the earnings before interest expense, provision for income taxes and depreciation and amortization expense of comparable peer companies. Significant estimates for our reporting unit included in our impairment analysis are our cash flow forecasts, our estimate of the market’s weighted average cost of capital and market multiples.
Beginning in late 2014 and extending throughout 2015, the energy markets experienced a significant reduction in oil and natural gas prices which has had a significant impact on the financial performance and operating results of many oil and natural gas companies. Such declines accelerated in the fourth quarter of 2015, resulting in higher borrowing costs for companies and a substantial reduction in forecasted capital spending across the energy industry leading to lower projected growth rates over the short-term. Such declines impacted our future cash flow forecasts, our market capitalization, and the market capitalization of peer companies. We identified these conditions as a triggering event, which required us to perform a goodwill impairment test as of December 31, 2015. As of this filing, we have not completed the goodwill impairment analysis, due to the complexities involved in determining the implied fair value of goodwill in the second step of the goodwill impairment test. However, based on the work performed to date, we have concluded that an impairment is probable and can be reasonably estimated. Accordingly, we recorded a full impairment of our remaining goodwill in the fourth quarter of 2015 of $3.7 million which is presented in goodwill impairment on the consolidated statement of operations. We expect to finalize the goodwill impairment analysis during the first quarter of 2016 and any resulting adjustment to the impairment will be recorded at that time.
Other (Income) Expense, Net
Other (income) expense, net, is primarily comprised of gains and losses from the sale of used assets.
Income Taxes
We account for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events included in the consolidated financial statements. Under this method, deferred tax assets and liabilities are determined based on the differences between the consolidated financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.
We record net deferred tax assets to the extent we believe these assets will more likely than not be realized. In making such a determination, we consider all available positive and negative evidence, including future reversals of existing taxable temporary differences, projected future taxable income, tax-planning strategies and results of recent operations. In the event we were to determine that we would be able to realize our deferred income tax assets in the future in excess of their net recorded amount, we would make an adjustment to the deferred tax asset valuation allowance, which would reduce the provision for income taxes.
F-9
We record uncertain tax positions in accordance with the accounting standard on income taxes under a two-step process whereby (1) we determine whether it is more likely than not that the tax positions will be sustained based on the technical merits of the position and (2) for those tax positions that meet the more-likely-than-not recognition threshold, we recognize the largest amount of tax benefit that is greater than 50 percent likely to be realized upon ultimate settlement with the related tax authority.
Hedging and Use of Derivative Instruments
We use derivative financial instruments to minimize the risks and/or costs associated with financial activities by managing our exposure to interest rate fluctuations on a portion of our debt obligations. We do not use derivative financial instruments for trading or other speculative purposes. We record interest rate swaps on the balance sheet as either derivative assets or derivative liabilities measured at their fair value. The fair value of our derivatives is estimated using a combination of the market and income approach based on forward London Interbank Offered Rate (“LIBOR”) curves. Changes in the fair value of the derivatives designated as cash flow hedges are deferred in accumulated other comprehensive income (loss), net of tax, to the extent the contracts are effective as hedges until settlement of the underlying hedged transaction. To qualify for hedge accounting treatment, we must formally document, designate and assess the effectiveness of the transactions. If the necessary correlation ceases to exist or if the anticipated transaction becomes improbable, we would discontinue hedge accounting and apply mark-to-market accounting. Amounts paid or received from interest rate swap agreements are charged or credited to interest expense and matched with the cash flows and interest expense of the debt being hedged, resulting in an adjustment to the effective interest rate.
Income (Loss) Attributable to Archrock Common Stockholders Per Common Share
Basic income (loss) attributable to Archrock common stockholders per common share is computed using the two-class method, which is an earnings allocation formula that determines net income per share for each class of common stock and participating security according to dividends declared and participation rights in undistributed earnings. Under the two-class method, basic income (loss) attributable to Archrock common stockholders per common share is determined by dividing income (loss) attributable to Archrock common stockholders after deducting amounts allocated to participating securities, by the weighted average number of common shares outstanding for the period. Participating securities include our unvested restricted stock and certain stock settled restricted stock units that have nonforfeitable rights to receive dividends or dividend equivalents, whether paid or unpaid. During periods of net loss, no effect is given to participating securities because they do not have a contractual obligation to participate in our losses.
Diluted income (loss) attributable to Archrock common stockholders per common share is computed using the weighted average number of shares outstanding adjusted for the incremental common stock equivalents attributed to outstanding options and warrants to purchase common stock, restricted stock units, stock to be issued pursuant to our employee stock purchase plan and convertible senior notes, unless their effect would be anti-dilutive.
The following table summarizes net income (loss) attributable to Archrock common stockholders used in the calculation of basic and diluted income (loss) per common share (in thousands):
Years Ended December 31, | |||||||||||
2015 | 2014 | 2013 | |||||||||
Loss from continuing operations attributable to Archrock stockholders | $ | (166,226 | ) | $ | (44,829 | ) | $ | (35,626 | ) | ||
Income from discontinued operations, net of tax | 60,408 | 142,995 | 158,790 | ||||||||
Net income (loss) attributable to Archrock shareholders | (105,818 | ) | 98,166 | 123,164 | |||||||
Less: Net income attributable to participating securities | (514 | ) | (495 | ) | — | ||||||
Net income (loss) attributable to Archrock common stockholders | $ | (106,332 | ) | $ | 97,671 | $ | 123,164 | ||||
F-10
The following table shows the potential shares of common stock that were included in computing diluted income (loss) attributable to Archrock common stockholders per common share (in thousands):
Years Ended December 31, | ||||||||
2015 | 2014 | 2013 | ||||||
Weighted average common shares outstanding including participating securities | 69,389 | 67,175 | 65,655 | |||||
Less: Weighted average participating securities outstanding | (956 | ) | (941 | ) | (1,201 | ) | ||
Weighted average common shares outstanding — used in basic income (loss) per common share | 68,433 | 66,234 | 64,454 | |||||
Net dilutive potential common shares issuable: | ||||||||
On exercise of options and vesting of restricted stock units | * | * | * | |||||
On settlement of employee stock purchase plan shares | * | * | * | |||||
On exercise of warrants | * | * | * | |||||
On conversion of 4.25% convertible senior notes due 2014 | ** | * | * | |||||
On conversion of 4.75% convertible senior notes due 2014 | ** | ** | * | |||||
Weighted average common shares outstanding — used in diluted income (loss) per common share | 68,433 | 66,234 | 64,454 | |||||
* | Excluded from diluted income (loss) per common share as their inclusion would have been anti-dilutive. |
** | Not applicable as the debt instrument was not outstanding during the period. |
There were no adjustments to net income (loss) attributable to Archrock common stockholders for the diluted earnings (loss) per common share calculation during the years ended December 31, 2015, 2014 and 2013.
The following table shows the potential shares of common stock issuable that were excluded from computing diluted income (loss) attributable to Archrock common stockholders per common share as their inclusion would have been anti-dilutive (in thousands):
Years Ended December 31, | ||||||||
2015 | 2014 | 2013 | ||||||
Net dilutive potential common shares issuable: | ||||||||
On exercise of options where exercise price is greater than average market value for the period | 572 | 515 | 734 | |||||
On exercise of options and vesting of restricted stock units | 214 | 490 | 547 | |||||
On settlement of employee stock purchase plan shares | — | 1 | 2 | |||||
On exercise of warrants | — | 10,666 | 12,426 | |||||
On conversion of 4.25% convertible senior notes due 2014 | — | 7,073 | 15,334 | |||||
On conversion of 4.75% convertible senior notes due 2014 | — | — | 119 | |||||
Net dilutive potential common shares issuable | 786 | 18,745 | 29,162 | |||||
Comprehensive Income (Loss)
Components of comprehensive income (loss) are net income (loss) and all changes in equity during a period except those resulting from transactions with owners. Our accumulated other comprehensive income (loss) consists of foreign currency translation adjustments, changes in the fair value of derivative financial instruments, net of tax, that are designated as cash flow hedges and to the extent the hedge is effective, amortization of terminated interest rate swaps and adjustments related to changes in our ownership of the Partnership.
F-11
The following tables present the changes in accumulated other comprehensive income (loss) by component, net of tax and excluding noncontrolling interest, during the years ended December 31, 2013, 2014 and 2015:
Derivatives Cash Flow Hedges | Foreign Currency Translation Adjustment | Total | |||||||||
Accumulated other comprehensive income (loss), January 1, 2013 | $ | (2,984 | ) | $ | 26,893 | $ | 23,909 | ||||
Loss recognized in other comprehensive income (loss), net of tax | (476 | ) | (1) | (2,960 | ) | (3,436 | ) | ||||
Loss reclassified from accumulated other comprehensive income (loss), net of tax | 2,114 | (2) | 7,491 | (3) | 9,605 | ||||||
Other comprehensive income attributable to Archrock stockholders | 1,638 | 4,531 | 6,169 | ||||||||
Accumulated other comprehensive income (loss), December 31, 2013 | $ | (1,346 | ) | $ | 31,424 | $ | 30,078 | ||||
Loss recognized in other comprehensive income (loss), net of tax | (1,295 | ) | (4) | (11,871 | ) | (13,166 | ) | ||||
(Gain) loss reclassified from accumulated other comprehensive income (loss), net of tax | 1,730 | (5) | (2,777 | ) | (6) | (1,047 | ) | ||||
Other comprehensive income (loss) attributable to Archrock stockholders | 435 | (14,648 | ) | (14,213 | ) | ||||||
Accumulated other comprehensive income (loss), December 31, 2014 | $ | (911 | ) | $ | 16,776 | $ | 15,865 | ||||
Loss recognized in other comprehensive income (loss), net of tax | (2,713 | ) | (7) | (3,558 | ) | (6,271 | ) | ||||
(Gain) loss reclassified from accumulated other comprehensive income (loss), net of tax | 2,054 | (8) | (13,218 | ) | (9) | (11,164 | ) | ||||
Other comprehensive loss attributable to Archrock stockholders | (659 | ) | (16,776 | ) | (17,435 | ) | |||||
Accumulated other comprehensive income (loss), December 31, 2015 | $ | (1,570 | ) | $ | — | $ | (1,570 | ) | |||
(1) | During the year ended December 31, 2013, we recognized a loss of $0.5 million and a tax benefit of $0.1 million, in other comprehensive income (loss), net of tax, related to changes in the fair value of derivative financial instruments. |
(2) | During the year ended December 31, 2013, we reclassified a $3.2 million loss to interest expense and a tax benefit of $1.1 million to provision for (benefit from) income taxes in our consolidated statements of operations from accumulated other comprehensive income (loss). |
(3) | During the year ended December 31, 2013, we reclassified losses of $7.5 million related to foreign currency translation adjustments to income from discontinued operations, net of tax in our consolidated statements of operations. These amounts represent cumulative foreign currency translation adjustments associated with Exterran Corporation’s contract operations and aftermarket services businesses in Canada and United Kingdom entity that were sold during the year ended December 31, 2013. |
(4) | During the year ended December 31, 2014, we recognized a loss of $2.0 million and a tax benefit of $0.7 million, in other comprehensive income (loss), net of tax, related to changes in the fair value of derivative financial instruments. |
(5) | During the year ended December 31, 2014, we reclassified a $2.6 million loss to interest expense and a tax benefit of $0.9 million to provision for (benefit from) income taxes in our consolidated statements of operations from accumulated other comprehensive income (loss). |
(6) | During the year ended December 31, 2014, we reclassified a gain of $2.8 million related to foreign currency translation adjustments to discontinued operations, net of tax, in our consolidated statements of operations. This amount represents cumulative foreign currency translation adjustments associated with Exterran Corporation’s contract operations and aftermarket services businesses in Australia, which were sold in December 2014, that previously had been recognized in accumulated other comprehensive income (loss). |
(7) | During the year ended December 31, 2015, we recognized a loss of $4.1 million and a tax benefit of $1.4 million, in other comprehensive income (loss), net of tax, related to changes in the fair value of derivative financial instruments. |
(8) | During the year ended December 31, 2015, we reclassified a $3.2 million loss to interest expense and a tax benefit of $1.1 million to provision for (benefit from) income taxes in our consolidated statements of operations from accumulated other comprehensive income (loss). |
F-12
(9) | During the year ended December 31, 2015, we reclassified a loss of $13.2 million related to foreign currency translation adjustments to additional paid in capital, in our consolidated balance sheet. This amount represents cumulative foreign currency translation adjustments associated with the businesses of Exterran Corporation which were spun-off in November 2015, that previously had been recognized in accumulated other comprehensive income (loss). See Note 2 (‘Discontinued Operations”) for further discussion of the Spin-off. |
Financial Instruments
Our financial instruments consist of cash, receivables, payables, interest rate swaps and debt. At December 31, 2015 and 2014, the estimated fair values of these financial instruments approximated their carrying amounts as reflected in our consolidated balance sheets. The fair value of our fixed rate debt was estimated based on quoted market yields in inactive markets, which are Level 2 inputs. The fair value of our floating rate debt was estimated using a discounted cash flow analysis based on interest rates offered on loans with similar terms to borrowers of similar credit quality, which are Level 3 inputs. See Note 11 (“Fair Value Measurements”) for additional information regarding the fair value hierarchy.
The following table summarizes the carrying amount and fair value of our debt as of December 31, 2015 and 2014 (in thousands):
December 31, 2015 | December 31, 2014 | ||||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | ||||||||||||
Fixed rate debt | $ | 691,465 | $ | 524,000 | $ | 1,040,295 | $ | 960,000 | |||||||
Floating rate debt | 897,000 | 897,000 | 985,500 | 986,000 | |||||||||||
Total debt | $ | 1,588,465 | $ | 1,421,000 | $ | 2,025,795 | $ | 1,946,000 | |||||||
GAAP requires that all derivative instruments (including certain derivative instruments embedded in other contracts) be recognized in the balance sheet at fair value and that changes in such fair values be recognized in earnings (loss) unless specific hedging criteria are met. Changes in the values of derivatives that meet these hedging criteria will ultimately offset related earnings effects of the hedged item pending recognition in earnings.
2. Discontinued Operations
Spin-off of Exterran Corporation
On November 3, 2015 (the “Distribution Date”), we completed the spin-off (the “Spin-off”) of our international contract operations, international aftermarket services and global fabrication businesses into a standalone public company operating as Exterran Corporation. To effect the Spin-off, we distributed on the Distribution Date, on a pro rata basis, all of the shares of Exterran Corporation common stock to our stockholders as of October 27, 2015 (the “Record Date”). Archrock stockholders received one share of Exterran Corporation common stock for every two shares of our common stock held at the close of business on the Record Date. Upon the completion of the Spin-off, we were renamed “Archrock, Inc.” and, on November 4, 2015, the ticker symbol for our common stock on the New York Stock Exchange was changed to “AROC.” Following the completion of the Spin-off, we and Exterran Corporation are independent, publicly traded companies with separate public ownership, boards of directors and management, and we continue to own and operate the U.S. contract operations and U.S. aftermarket services businesses that we previously owned. Additionally, we continue to hold our interests in the Partnership. Effective on November 3, 2015, the Partnership was renamed “Archrock Partners, L.P.,” and, on November 4, 2015, the ticker symbol for its common units on the Nasdaq Global Select Market was changed to “APLP.” The Exterran Corporation business has been reported as discontinued operations, net of tax, in our consolidated statement of operations for all periods presented and was previously included in the international contract operations segment, fabrication segment and aftermarket services segment. Subsequent to the Spin-off, we no longer operate in the International contract operations, International aftermarket services or Fabrication segments.
F-13
In order to effect the Spin-off and govern our relationship with Exterran Corporation after the Spin-off, we entered into several agreements with Exterran Corporation on November 3, 2015:
• | The separation and distribution agreement contains the key provisions relating to the separation of our business from Exterran Corporation’s business. The separation and distribution agreement identifies the assets and rights that were transferred, liabilities that were assumed or retained and contracts and related matters that were assigned to us or Exterran Corporation in the Spin-off and describes how these transfers, assumptions and assignments occurred. Pursuant to the separation and distribution agreement, on November 3, 2015, a subsidiary of Exterran Corporation transferred net proceeds of $532.6 million from borrowings under the Exterran Corporation credit facility to us to allow for the repayment of a portion of our indebtedness. On November 3, 2015, we terminated our former credit facility and repaid all borrowings and accrued and unpaid interest outstanding on the repayment date totaling $326.5 million. Our new capital structure includes a $350.0 million revolving credit facility that became available on November 3, 2015. On December 4, 2015, we redeemed for cash the $350.0 million aggregate principal amount of our 7.25% Notes at a redemption price equal to 101.813% of the principal amount thereof plus accrued but unpaid interest to the redemption date for $369.2 million. In addition, the separation and distribution agreement contains certain noncompetition provisions addressing restrictions for three years after the Spin-off on Exterran Corporation’s ability to provide contract operations and aftermarket services in the United States and on our ability to provide contract operations and aftermarket services outside of the United States and to provide products for sale worldwide that compete with Exterran Corporation’s current product sales business, subject to certain exceptions. The separation and distribution agreement also governs the treatment of aspects relating to indemnification, insurance, confidentiality and cooperation. Additionally, the separation and distribution agreement specifies our right to receive payments from a subsidiary of Exterran Corporation based on a notional amount corresponding to payments received by Exterran Corporation’s subsidiaries from PDVSA Gas in respect of the sale of Exterran Corporation’s subsidiaries’ and joint ventures’ previously nationalized assets promptly after such amounts are collected by Exterran Corporation’s subsidiaries. As of December 31, 2015, we have received payments, including annual charges, of approximately $493.0 million ($50.0 million of which was used to repay insurance proceeds previously collected under the policy we maintained for the risk of expropriation). Pursuant to the separation and distribution agreement, Exterran Corporation or its subsidiary is due to receive the remaining principal amount as of December 31, 2015 of approximately $79.3 million in installments through the third quarter of 2016. As these remaining proceeds are received, Exterran Corporation intends to contribute to us an amount equal to such proceeds pursuant to the terms of the separation and distribution agreement. In January 2016, Exterran Corporation received an additional installment payment, including an annual charge, of $5.2 million from PDVSA Gas relating to its previously nationalized Venezuelan joint ventures’ assets and transferred cash to us equal to that amount in January 2016. The separation and distribution agreement also specifies our right to receive a $25.0 million cash payment from a subsidiary of Exterran Corporation promptly following the occurrence of a qualified capital raise as defined in the Exterran Corporation credit agreement. |
• | The tax matters agreement governs the respective rights, responsibilities and obligations of Exterran Corporation and us with respect to tax liabilities and benefits, tax attributes, the preparation and filing of tax returns, the control of audits and other tax proceedings and certain other matters regarding taxes. |
• | The employee matters agreement governs the allocation of liabilities and responsibilities between us and Exterran Corporation relating to employee compensation and benefit plans and programs, including the treatment of retirement, health and welfare plans and equity and other incentive plans and awards. The agreement contains provisions regarding stock-based compensation. See Note 15 (“Common Stockholders’ Equity”) for additional information relating to the Archrock Stock Incentive Plan. |
• | The transition services agreement sets forth the terms on which Exterran Corporation will provide to us, and we will provide to Exterran Corporation, on a temporary basis, certain services or functions that the companies historically have shared. Transition services provided to us by Exterran Corporation and to Exterran Corporation by us may include accounting, administrative, payroll, human resources, environmental health and safety, real estate, fleet, financial audit support, legal, tax, treasury and other support and corporate services, and each service will be provided at a predetermined rate set forth in the transition services agreement. Each service provided under the agreement will have its own duration generally less than one year but not to exceed two years, extension terms and monthly cost, and the transition services agreement will terminate upon cessation of all services provided thereunder. For the period from November 4, 2015 through December 31, 2015, we recorded other income of $0.4 million and selling, general and administrative expense of $0.6 million associated with the services under the transition services agreement. |
F-14
• | The supply agreement sets forth the terms under which Exterran Corporation will provide manufactured equipment, including the design, engineering, manufacturing and sale of natural gas compression equipment, on an exclusive basis to us and the Partnership. This supply agreement will have an initial term of two years, subject to certain cancellation clauses, and is extendible for additional one-year terms by mutual agreement of the parties. Pursuant to the supply agreement, each of us and the Partnership will be required to purchase its requirements of newly-manufactured compression equipment from Exterran Corporation, subject to certain exceptions. For the period from November 4, 2015 through December 31, 2015, we purchased $44.4 million of newly-manufactured compression equipment from Exterran Corporation. |
• | The storage agreements set forth the terms under which Exterran Corporation will provide each of us and the Partnership with storage space for equipment purchased under the supply agreement, as well as the terms under which we will provide storage space to Exterran Corporation for certain of its equipment. |
• | The services agreements set forth the terms under which Exterran Corporation will provide us (or our customers on our behalf) with engineering, preservation and installation and commissioning services and we will provide Exterran Corporation (or its customers on its behalf) with make-ready, parts sales, preservation and installation and commissioning services. These services agreements will continue in effect until terminated by either party on 30 days’ written notice. |
Generally, the separation and distribution agreement provides for cross-indemnities principally designed to place financial responsibility for the obligations and liabilities of our business with us and financial responsibility for the obligations and liabilities of Exterran Corporation’s business with Exterran Corporation. Pursuant to the separation and distribution agreement, we and Exterran Corporation will generally release the other party from all claims arising prior to the Spin-off that relate to the other party’s business.
Other discontinued operations activity
In December 2013, we abandoned our contract water treatment business as part of our continued emphasis on simplification and focus on our core businesses. The abandonment of this business meets the criteria established for recognition as discontinued operations under GAAP. Therefore, our contract water treatment business has been reported as discontinued operations, net of tax, in our consolidated statement of operations. This business was previously included in our contract operations business segment.
The following table summarizes the operating results of discontinued operations (in thousands):
Years Ended December 31, | |||||||||||||||||||||||||||||||||||
2015 | 2014 | 2013 | |||||||||||||||||||||||||||||||||
Exterran Corporation (1) | Contract Water Treatment Business | Total | Exterran Corporation | Contract Water Treatment Business | Total | Exterran Corporation | Contract Water Treatment Business | Total | |||||||||||||||||||||||||||
Revenue | $ | 1,424,184 | $ | — | $ | 1,424,184 | $ | 1,940,585 | $ | — | $ | 1,940,585 | $ | 2,297,632 | $ | 3,425 | $ | 2,301,057 | |||||||||||||||||
Cost of sales (excluding depreciation and amortization expense) | 1,017,912 | 222 | 1,018,134 | 1,364,051 | 479 | 1,364,530 | 1,726,420 | 3,015 | 1,729,435 | ||||||||||||||||||||||||||
Selling, general and administrative | 171,912 | — | 171,912 | 245,103 | 30 | 245,133 | 239,322 | 337 | 239,659 | ||||||||||||||||||||||||||
Depreciation and amortization | 124,321 | — | 124,321 | 173,803 | — | 173,803 | 140,029 | — | 140,029 | ||||||||||||||||||||||||||
Long-lived asset impairment | 14,264 | — | 14,264 | 3,851 | 319 | 4,170 | 11,941 | 2,355 | 14,296 | ||||||||||||||||||||||||||
Restructuring charges | 43,884 | — | 43,884 | 2,159 | — | 2,159 | — | — | — | ||||||||||||||||||||||||||
Interest expense | 1,578 | — | 1,578 | 1,905 | — | 1,905 | 3,551 | — | 3,551 | ||||||||||||||||||||||||||
Equity in income of non-consolidated affiliates | (15,152 | ) | — | (15,152 | ) | (14,553 | ) | — | (14,553 | ) | (19,000 | ) | — | (19,000 | ) | ||||||||||||||||||||
Other (income) loss, net (2) | (23,782 | ) | — | (23,782 | ) | (65,976 | ) | (27 | ) | (66,003 | ) | (68,115 | ) | 1,002 | (67,113 | ) | |||||||||||||||||||
Income (loss) from discontinued operations before income taxes | 89,247 | (222 | ) | 89,025 | 230,242 | (801 | ) | 229,441 | 263,484 | (3,284 | ) | 260,200 | |||||||||||||||||||||||
Provision for (benefit from) income taxes | 28,705 | (88 | ) | 28,617 | 86,723 | (277 | ) | 86,446 | 102,559 | (1,149 | ) | 101,410 | |||||||||||||||||||||||
Income (loss) from discontinued operations, net of tax | $ | 60,542 | $ | (134 | ) | $ | 60,408 | $ | 143,519 | $ | (524 | ) | $ | 142,995 | $ | 160,925 | $ | (2,135 | ) | $ | 158,790 | ||||||||||||||
(1) | Includes the results of operations of Exterran Corporation and costs directly attributable to the Spin-off. |
F-15
(2) | Includes income from discontinued operations, net of tax, related to previously discontinued Venezuela and Canada operations of $56.8 million, $73.2 million, and $66.1 million for the year ended December 31, 2015, 2014, and 2013, respectively. |
The following table summarizes the balance sheet data for discontinued operations (in thousands):
December 31, 2015 | December 31, 2014 | ||||||||||||||||||||||
Exterran Corporation | Contract Water Treatment Business | Total | Exterran Corporation | Contract Water Treatment Business | Total | ||||||||||||||||||
Cash and cash equivalents | $ | — | $ | — | $ | — | $ | 39,792 | $ | — | $ | 39,792 | |||||||||||
Restricted cash | — | — | — | 1,490 | — | 1,490 | |||||||||||||||||
Accounts receivable | — | — | — | 398,072 | 69 | 398,141 | |||||||||||||||||
Inventory | — | — | — | 257,785 | — | 257,785 | |||||||||||||||||
Costs and estimated earnings in excess of billings on uncompleted contracts | — | — | — | 120,938 | — | 120,938 | |||||||||||||||||
Other current assets | 420 | — | 420 | 54,012 | — | 54,012 | |||||||||||||||||
Total current assets associated with discontinued operations | 420 | — | 420 | 872,089 | 69 | 872,158 | |||||||||||||||||
Property, plant and equipment | — | — | — | 954,811 | — | 954,811 | |||||||||||||||||
Intangibles and other assets, net | 5,714 | — | 5,714 | 238,767 | — | 238,767 | |||||||||||||||||
Deferred income taxes | — | 15,486 | 15,486 | — | 17,469 | 17,469 | |||||||||||||||||
Total assets associated with discontinued operations | $ | 6,134 | $ | 15,486 | $ | 21,620 | $ | 2,065,667 | $ | 17,538 | $ | 2,083,205 | |||||||||||
Accounts payable | $ | — | $ | — | $ | — | $ | 162,040 | $ | 1 | $ | 162,041 | |||||||||||
Accrued liabilities | — | — | — | 169,066 | 727 | 169,793 | |||||||||||||||||
Deferred income taxes | 420 | — | 420 | — | — | — | |||||||||||||||||
Deferred revenue | — | — | — | 64,820 | — | 64,820 | |||||||||||||||||
Billings on uncompleted contracts in excess of costs and estimated earnings | — | — | — | 76,277 | — | 76,277 | |||||||||||||||||
Total current liabilities associated with discontinued operations | 420 | — | 420 | 472,203 | 728 | 472,931 | |||||||||||||||||
Long-term debt | — | — | — | 1,107 | — | 1,107 | |||||||||||||||||
Deferred income taxes | 5,714 | — | 5,714 | 39,100 | — | 39,100 | |||||||||||||||||
Other long-term liabilities | — | — | — | 68,876 | — | 68,876 | |||||||||||||||||
Total liabilities associated with discontinued operations | $ | 6,134 | $ | — | $ | 6,134 | $ | 581,286 | $ | 728 | $ | 582,014 | |||||||||||
3. Business Acquisitions
August 2014 MidCon Acquisition
On August 8, 2014, the Partnership completed an acquisition of natural gas compression assets, including a fleet of 162 compressor units, comprising approximately 110,000 horsepower from MidCon Compression, L.L.C. (“MidCon”) for $130.1 million. The purchase price was funded with borrowings under the Partnership’s revolving credit facility. The majority of the horsepower acquired is utilized under a five-year contract operations services agreement with BHP Billiton Petroleum (“BHP Billiton”), which expires in March 2019, to provide compression services. In connection with the acquisition, the contract operations services agreement with BHP Billiton was assigned to the Partnership effective as of the closing. During the year ended December 31, 2014, the Partnership incurred transaction costs of approximately $1.0 million related to this acquisition, which is reflected in other (income) expense, net, in our consolidated statements of operations.
In accordance with the terms of the purchase and sale agreement between the Partnership and MidCon relating to this acquisition, the Partnership directed MidCon to sell a tract of real property and the facility located thereon, a fleet of vehicles, personal property and parts inventory to our wholly-owned subsidiary Archrock Services, L.P. (“ASLP”), an indirect parent company of the Partnership, for $4.1 million. The assets acquired by ASLP are used in conjunction with the compression units the Partnership acquired from MidCon to provide compression services. The acquisition of the assets by the Partnership and ASLP from MidCon is referred to as the “August 2014 MidCon Acquisition.”
F-16
We accounted for the August 2014 MidCon Acquisition using the acquisition method, which requires, among other things, assets acquired and liabilities assumed to be recorded at their fair value on the acquisition date. The excess of the consideration transferred over those fair values is recorded as goodwill. The following table summarizes the purchase price allocation based on estimated fair values of the acquired assets and liabilities as of the acquisition date (in thousands):
Fair Value | |||
Inventory | $ | 2,302 | |
Property, plant and equipment | 80,154 | ||
Goodwill | 3,738 | ||
Intangible assets | 48,373 | ||
Current liabilities | (372 | ) | |
Purchase price | $ | 134,195 | |
Property, Plant and Equipment, Goodwill and Intangible Assets Acquired
Property, plant and equipment is primarily comprised of compression equipment that will be depreciated on a straight-line basis over an estimated average remaining useful life of 24 years.
Goodwill of $3.7 million resulting from the acquisition is attributable to the expansion of our services in the region and was assigned to our contract operations segment. The goodwill recorded is considered to have an indefinite life and is reviewed annually for impairment or more frequently if indicators of impairment exist. At December 31, 2015, we recorded a full impairment of our goodwill. See Note 6 (“Goodwill”) for further discussion of goodwill impairment.
The amount of finite life intangible assets, and their associated average useful lives, was determined based on the period which the assets are expected to contribute directly or indirectly to our future cash flows, and consisted of the following:
Amount (In thousands) | Average Useful Life | ||||
Customer related | $ | 21,590 | 25 years | ||
Contract based | 26,783 | 5 years | |||
Total acquired identifiable intangible assets | $ | 48,373 | |||
The results of operations attributable to the assets and liabilities acquired in the August 2014 MidCon Acquisition have been included in our consolidated financial statements as part of our contract operations segment since the date of acquisition.
April 2014 MidCon Acquisition
On April 10, 2014, the Partnership completed an acquisition of natural gas compression assets, including a fleet of 337 compressor units, comprising approximately 444,000 horsepower from MidCon for $352.9 million. The purchase price was funded with the net proceeds from the Partnership’s public sale of 6.2 million common units and a portion of the net proceeds from the Partnership’s issuance of $350.0 million aggregate principal amount of 6% senior notes due October 2022 (the “Partnership 2014 Notes”). The compressor units were previously used by MidCon to provide compression services to a subsidiary of Access Midstream Partners LP (“Access”). Effective as of the closing of the acquisition, the Partnership and Access entered into a seven-year contract operations services agreement under which the Partnership provides compression services to Williams Partners, L.P. (formerly Access). During the year ended December 31, 2014, the Partnership incurred transaction costs of approximately $1.5 million related to this acquisition, which is reflected in other (income) expense, net, in our consolidated statements of operations.
In accordance with the terms of the purchase and sale agreement between the Partnership and MidCon relating to this acquisition, the Partnership directed MidCon to sell a tract of real property and the facility located thereon, a fleet of vehicles, personal property and parts inventory to our wholly-owned subsidiary ASLP, an indirect parent company of the Partnership, for $7.7 million. The assets acquired by ASLP are used in conjunction with the compression units the Partnership acquired from MidCon to provide compression services. The acquisition of the assets by the Partnership and ASLP from MidCon is referred to as the “April 2014 MidCon Acquisition.”
F-17
We accounted for the April 2014 MidCon Acquisition using the acquisition method, which requires, among other things, assets acquired and liabilities assumed to be recorded at their fair value on the acquisition date. The following table summarizes the purchase price allocation based on estimated fair values of the acquired assets and liabilities as of the acquisition date (in thousands):
Fair Value | |||
Inventory | $ | 4,357 | |
Property, plant and equipment | 314,556 | ||
Intangible assets | 42,474 | ||
Current liabilities | (827 | ) | |
Purchase price | $ | 360,560 | |
Property, Plant and Equipment and Intangible Assets Acquired
Property, plant and equipment is primarily comprised of compression equipment that will be depreciated on a straight-line basis over an estimated average remaining useful life of 25 years.
The amount of finite life intangible assets, and their associated average useful lives, was determined based on the period which the assets are expected to contribute directly or indirectly to our future cash flows, and consisted of the following:
Amount (In thousands) | Average Useful Life | ||||
Customer related | $ | 4,701 | 25 years | ||
Contract based | 37,773 | 7 years | |||
Total acquired identifiable intangible assets | $ | 42,474 | |||
The results of operations attributable to the assets and liabilities acquired in the April 2014 MidCon Acquisition have been included in our consolidated financial statements as part of our contract operations segment since the date of acquisition.
Unaudited Pro Forma Financial Information
The unaudited Pro forma financial information for the years ended December 31, 2014 and 2013 has been included to give effect to the additional assets acquired in the August 2014 MidCon Acquisition and the April 2014 MidCon Acquisition. The August 2014 MidCon Acquisition and the April 2014 MidCon Acquisition are presented in the unaudited pro forma financial information as though these transactions occurred as of January 1, 2013. The unaudited pro forma financial information reflects the following transactions:
As related to the August 2014 MidCon Acquisition:
• | the Partnership’s acquisition in August 2014 of natural gas compression assets and identifiable intangible assets from MidCon; |
• | our wholly-owned subsidiary ASLP’s, an indirect parent company of the Partnership, acquisition from MidCon, as directed by the Partnership, of a tract of real property and the facility located thereon, a fleet of vehicles, personal property and parts inventory; |
• | the Partnership’s borrowings under its revolving credit facility to pay $130.1 million to MidCon for the August 2014 MidCon Acquisition; and |
• | our borrowings under our revolving credit facility to pay $4.1 million to MidCon for assets acquired by ASLP in the August 2014 MidCon Acquisition. |
As related to the April 2014 MidCon Acquisition:
• | the Partnership’s acquisition in April 2014 of natural gas compression assets and identifiable intangible assets from MidCon; |
F-18
• | our wholly-owned subsidiary ASLP’s, an indirect parent company of the Partnership, acquisition from MidCon, as directed by the Partnership, of a tract of real property and the facility located thereon, a fleet of vehicles, personal property and parts inventory; |
• | the Partnership’s issuance of 6.2 million common units to the public and approximately 126,000 general partner units to us; |
• | the Partnership’s issuance of $350.0 million aggregate principal amount of the Partnership 2014 Notes; |
• | the Partnership’s use of proceeds from the issuance of common units, general partner units and the Partnership 2014 Notes to pay $352.9 million to MidCon for the April 2014 MidCon Acquisition and to pay down $157.5 million on its revolving credit facility; and |
• | our borrowings under our revolving credit facility to pay $7.7 million to MidCon for assets acquired by one of our wholly-owned subsidiaries in the April 2014 MidCon Acquisition. |
The unaudited pro forma financial information below is presented for informational purposes only and is not necessarily indicative of our results of operations that would have occurred had each transaction been consummated at the beginning of the period presented, nor is it necessarily indicative of future results. The unaudited pro forma financial information below was derived by adjusting our historical financial statements.
The following table shows unaudited pro forma financial information for the years ended December 31, 2014 and 2013 (in thousands, except per share amounts):
Years Ended December 31, | |||||||
2014 | 2013 | ||||||
Revenue | $ | 996,961 | $ | 974,518 | |||
Net income attributable to Archrock common stockholders | $ | 100,208 | $ | 127,028 | |||
Basic net income per common share attributable to Archrock common stockholders | $ | 1.51 | $ | 1.97 | |||
Diluted net income per common share attributable to Archrock common stockholders | $ | 1.51 | $ | 1.97 | |||
4. Inventory
Inventory consisted of the following amounts (in thousands):
December 31, | |||||||
2015 | 2014 | ||||||
Parts and supplies | $ | 109,634 | $ | 120,646 | |||
Work in progress | 19,777 | 25,140 | |||||
Inventory | $ | 129,411 | $ | 145,786 | |||
During the years ended December 31, 2015, 2014 and 2013, we recorded $4.3 million, $8.9 million and $3.9 million, respectively, in inventory write-downs and reserves for inventory which was obsolete, excess or carried at a price above market value. As of December 31, 2015 and 2014, we had inventory reserves of $9.8 million and $11.5 million, respectively.
F-19
5. Property, Plant and Equipment, net
Property, plant and equipment, net, consisted of the following (in thousands):
December 31, | |||||||
2015 | 2014 | ||||||
Compression equipment, facilities and other fleet assets | $ | 3,292,364 | $ | 3,401,594 | |||
Land and buildings | 53,175 | 51,391 | |||||
Transportation and shop equipment | 108,998 | 103,207 | |||||
Other | 109,291 | 84,382 | |||||
3,563,828 | 3,640,574 | ||||||
Accumulated depreciation | (1,296,040 | ) | (1,268,493 | ) | |||
Property, plant and equipment, net | $ | 2,267,788 | $ | 2,372,081 | |||
Depreciation expense was $212.0 million, $200.0 million and $180.7 million during the years ended December 31, 2015, 2014 and 2013, respectively. Assets under construction of $71.1 million and $82.6 million were primarily included in compression equipment, facilities and other fleet assets at December 31, 2015 and 2014, respectively. We capitalized $0.3 million, $0.2 million and $0.3 million of interest related to construction in process during the years ended December 31, 2015, 2014 and 2013, respectively.
6. Goodwill
Goodwill acquired in connection with business combinations represents the excess of consideration over the fair value of tangible and identifiable intangible net assets acquired. Certain assumptions and estimates are employed in determining the fair value of assets acquired and liabilities assumed, as well as in determining the allocation of goodwill to the appropriate reporting unit.
We review the carrying value of our goodwill for potential impairment in the fourth quarter of every year, or whenever events or other circumstances indicate that we may not be able to recover the carrying amount. We first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. We may elect to perform the two-step goodwill impairment test without completing a qualitative assessment.
If a two-step process goodwill impairment test is elected or required, the first step is to compare the implied fair value of our reporting unit with its carrying value (including the goodwill). If the implied fair value of the reporting unit is higher than the carrying value, no impairment is deemed to exist and no further testing is required. If, however, the implied fair value of the reporting unit is below the recorded carrying value, then a second step must be performed to determine the goodwill impairment required, if any. We calculate the implied fair value of the reporting unit goodwill by allocating the estimated fair value of the reporting unit to all of the assets and liabilities of the reporting unit as if the reporting unit had been acquired in a business combination. If the carrying value of the reporting unit’s goodwill exceeds the implied fair value of the goodwill, we recognize an impairment loss for that excess amount.
Determining the fair value of a reporting unit under the first step of the goodwill impairment test is judgmental in nature and involves the use of significant estimates and assumptions, which have a significant impact on the fair value determined. We determine the fair value of our reporting unit using both the expected present value of future cash flows and a market approach. Each approach is weighted 50% in determining our calculated fair value. The present value of future cash flows is estimated using our most recent forecast and the weighted average cost of capital. The market approach uses a market multiple on earnings before interest expense, provision for income taxes and depreciation and amortization expense of comparable peer companies. Significant estimates for our reporting unit included in our impairment analysis are our cash flow forecasts, our estimate of the market’s weighted average cost of capital and market multiples.
F-20
Beginning in late 2014 and extending throughout 2015, the energy markets experienced a significant reduction in oil and natural gas prices which has had a significant impact on the financial performance and operating results of many oil and natural gas companies. Such declines accelerated in the fourth quarter of 2015, resulting in higher borrowing costs for companies and a substantial reduction in forecasted capital spending across the energy industry leading to lower projected growth rates over the short-term. Such declines impacted our future cash flow forecasts, our market capitalization, and the market capitalization of peer companies. We identified these conditions as a triggering event, which required us to perform a goodwill impairment test as of December 31, 2015. As of this filing, we have not completed the goodwill impairment analysis, due to the complexities involved in determining the implied fair value of goodwill in the second step of the goodwill impairment test. However, based on the work performed to date, we have concluded that an impairment is probable and can be reasonably estimated. Accordingly, we recorded a full impairment of our remaining goodwill in the fourth quarter of 2015 of $3.7 million. We expect to finalize the goodwill impairment analysis during the first quarter of 2016 and any resulting adjustment to the impairment will be recorded at that time.
For the years ended December 31, 2014 and 2013, we determined that there was no impairment of goodwill.
For the year ended December 31, 2013, there were no additions or acquisitions that resulted in the recognition of goodwill.
During the year ended December 31, 2014, we acquired $3.7 million in goodwill associated with the August 2014 MidCon Acquisition.
The following table presents the change in the carrying value of goodwill for the year ended December 31, 2015 (in thousands):
December 31, 2015 | ||
Goodwill as of January 1, 2015 | 3,738 | |
Goodwill acquired during year | — | |
Impairment losses | (3,738 | ) |
Goodwill as of December 31, 2015 | — | |
7. Intangible and Other Assets, net
Intangible and other assets, net, consisted of the following (in thousands):
December 31, | |||||||
2015 | 2014 | ||||||
Deferred financing costs, net | $ | 20,612 | $ | 23,795 | |||
Intangible assets, net | 100,822 | 117,915 | |||||
Other | 11,038 | 12,443 | |||||
Intangibles and other assets, net | $ | 132,472 | $ | 154,153 | |||
Intangible assets and deferred financing costs consisted of the following (in thousands):
December 31, 2015 | December 31, 2014 | ||||||||||||||
Gross Carrying Amount | Accumulated Amortization | Gross Carrying Amount | Accumulated Amortization | ||||||||||||
Deferred financing costs | $ | 40,066 | $ | (19,454 | ) | $ | 41,790 | $ | (17,995 | ) | |||||
Marketing related (5 year life) | 330 | (312 | ) | 330 | (268 | ) | |||||||||
Customer related (10-25 year life) | 107,008 | (53,957 | ) | 107,008 | (47,859 | ) | |||||||||
Contract based (5-7 year life) | 74,336 | (26,583 | ) | 74,336 | (15,632 | ) | |||||||||
Intangible assets and deferred financing costs | $ | 221,740 | $ | (100,306 | ) | $ | 223,464 | $ | (81,754 | ) | |||||
F-21
Amortization of deferred financing costs totaled $6.4 million, $6.0 million and $7.7 million in 2015, 2014 and 2013, respectively, and was recorded to interest expense in our consolidated statements of operations. As discussed further in Note 9 (“Long-Term Debt”), $2.9 million of deferred financing costs were expensed in 2015 and are reflected in debt extinguishment costs in our consolidated statements of operations. Amortization of intangible assets totaled $17.1 million, $12.3 million and $6.8 million during the years ended December 31, 2015, 2014 and 2013, respectively.
Estimated future intangible amortization expense is as follows (in thousands):
2016 | $ | 16,618 | |
2017 | 16,091 | ||
2018 | 15,673 | ||
2019 | 13,047 | ||
2020 | 9,562 | ||
Thereafter | 29,831 | ||
Total | $ | 100,822 | |
8. Accrued Liabilities
Accrued liabilities consisted of the following (in thousands):
December 31, | |||||||
2015 | 2014 | ||||||
Accrued salaries and other benefits | $ | 27,066 | $ | 39,182 | |||
Accrued income and other taxes | 15,006 | 20,807 | |||||
Accrued interest | 12,675 | 14,286 | |||||
Interest rate swaps fair value | 4,608 | 4,958 | |||||
Accrued other liabilities | 20,698 | 11,949 | |||||
Accrued liabilities | $ | 80,053 | $ | 91,182 | |||
9. Long-Term Debt
Long-term debt consisted of the following (in thousands):
December 31, | |||||||
2015 | 2014 | ||||||
Revolving credit facility due July 2016 | $ | — | $ | 375,500 | |||
Revolving credit facility due November 2020 | 166,500 | — | |||||
Partnership’s revolving credit facility due May 2018 | 580,500 | 460,000 | |||||
Partnership’s term loan facility due May 2018 | 150,000 | 150,000 | |||||
Partnership’s 6% senior notes due April 2021 (presented net of the unamortized discount of $3.9 million and $4.5 million, respectively) | 346,138 | 345,528 | |||||
Partnership’s 6% senior notes due October 2022 (presented net of the unamortized discount of $4.7 million and $5.2 million, respectively) | 345,327 | 344,767 | |||||
7.25% senior notes due December 2018 | — | 350,000 | |||||
Long-term debt | $ | 1,588,465 | $ | 2,025,795 | |||
F-22
Archrock Revolving Credit Facility
In October 2015, in connection with the Spin-off, we entered into a five-year, $350.0 million revolving credit facility (the “Credit Facility”). Availability under the Credit Facility was subject to the satisfaction of certain conditions precedent, including (i) the payoff and termination of our former credit facility and (ii) the consummation of the Spin-off on or before January 4, 2016 (the date on which those conditions are satisfied is referred to as the “Archrock Initial Availability Date”). As a result of the completion of the Spin-off, the Archrock Initial Availability Date was November 3, 2015 and the Credit Facility will mature in November 2020. We incurred approximately $3.7 million in transaction costs related to the Credit Facility during the year ended December 31, 2015. These costs are included in Intangibles and other assets, net and will be amortized over the term of the facility. On November 3, 2015, we terminated our former credit facility and repaid $326.5 million in borrowings and accrued and unpaid interest outstanding on the repayment date. As a result of the modification, we wrote-off $0.4 million related to unamortized deferred financing costs associated with the former credit facility in the fourth quarter of 2015, which is included in interest expense in our consolidated statements of operations.
As of December 31, 2015, we had $166.5 million in outstanding borrowings and $10.0 million in outstanding letters of credit under the Credit Facility. At December 31, 2015, taking into account guarantees through letters of credit, we had undrawn and available capacity of $173.5 million under the Credit Facility.
Borrowings under the Credit Facility bear interest at a base rate or LIBOR, at our option, plus an applicable margin. Depending on our Total Leverage Ratio (as defined in the credit agreement), the applicable margin for revolving loans varies (i) in the case of LIBOR loans, from 1.75% to 2.75% and (ii) in the case of base rate loans, from 0.75% to 1.75%. The base rate is the highest of the prime rate announced by Wells Fargo Bank, National Association, the Federal Funds Rate plus 0.5% and one-month LIBOR plus 1.0%. At December 31, 2015, all amounts outstanding under the Credit Facility were LIBOR loans and the applicable margin was 1.75%. The weighted average annual interest rate at both December 31, 2015 and 2014 on the outstanding balance under the Credit Facility was 2.1% and 1.7%, respectively.
We and our Significant Domestic Subsidiaries (as defined in the credit agreement) guarantee the debt under the Credit Facility. Borrowings under the Credit Facility are secured by substantially all of the personal property assets and certain real property assets of us and our Significant Domestic Subsidiaries, including all of the equity interests of our U.S. subsidiaries (other than certain excluded subsidiaries). The Partnership does not guarantee the debt under the Credit Facility, its assets are not collateral under the Credit Facility and the general partner units in the Partnership are not pledged under the Credit Facility. Subject to certain conditions, at our request, and with the approval of the lenders, the aggregate commitments under the Credit Facility may be increased by up to an additional $100 million.
The Credit Facility contains various covenants with which we or certain of our subsidiaries must comply, including, but not limited to, limitations on the incurrence of indebtedness, investments, liens on assets, repurchasing equity and making distributions, transactions with affiliates, mergers, consolidations, dispositions of assets and other provisions customary in similar types of agreements. We are also subject to financial covenants, including a ratio of earnings before interest, taxes, depreciation and amortization (“EBITDA”) (as defined in the credit agreement) to Total Interest Expense (as defined in the credit agreement) of not less than 2.25 to 1.0 and a ratio of consolidated Total Debt (as defined in the credit agreement) to EBITDA of not greater than 4.25 to 1.0 (subject to a temporary increase to 4.75 to 1.0 for any quarter during which an acquisition meeting certain thresholds is completed and for the following two quarters after the acquisition closes).
The Partnership Revolving Credit Facility and Term Loan
In November 2010, the Partnership entered into an amendment and restatement of its senior secured credit agreement (the “Partnership Credit Agreement”) to provide for a five-year $550.0 million senior secured credit facility, consisting of a $400.0 million revolving credit facility and a $150.0 million term loan facility. The revolving borrowing capacity under this facility was increased to $550.0 million in March 2011 and to $750.0 million in March 2012. In March 2013, the Partnership Credit Agreement was amended to reduce the borrowing capacity under its revolving credit facility to $650.0 million and extend the maturity date of the term loan and revolving credit facilities to May 2018. As a result of the March 2013 amendment, we expensed $0.7 million of unamortized deferred financing costs, which is reflected in interest expense in our consolidated statements of operations. In February 2015, the Partnership amended the Partnership Credit Agreement, which among other things, increased the borrowing capacity under its revolving credit facility by $250.0 million to $900.0 million. During the years ended December 31, 2015 and 2014 the Partnership incurred transaction costs of approximately $1.3 million and $4.3 million, respectively, related to the amendments to the Partnership Credit Agreement. These costs were included in intangible and other assets, net, and are being amortized over the terms of the facilities. As of December 31, 2015, the Partnership had undrawn and available capacity of $319.5 million under its revolving credit facility.
F-23
The Partnership’s revolving credit and term loan facilities bear interest at a base rate or LIBOR, at the Partnership’s option, plus an applicable margin. Depending on the Partnership’s leverage ratio, the applicable margin for the revolving and term loans varies (i) in the case of LIBOR loans, from 2.0% to 3.0% and (ii) in the case of base rate loans, from 1.0% to 2.0%. The base rate is the highest of the prime rate announced by Wells Fargo Bank, National Association, the Federal Funds Effective Rate plus 0.5% and one-month LIBOR plus 1.0%. At December 31, 2015, all amounts outstanding under these facilities were LIBOR loans and the applicable margin was 2.5%. The weighted average annual interest rate on the outstanding balance of these facilities at December 31, 2015 and 2014, excluding the effect of interest rate swaps, was 2.8% and 2.7%, respectively.
Borrowings under the Partnership Credit Agreement are secured by substantially all of the U.S. personal property assets of the Partnership and its Significant Domestic Subsidiaries (as defined in the Partnership Credit Agreement), including all of the membership interests of the Partnership’s Domestic Subsidiaries (as defined in the Partnership Credit Agreement). As of December 31, 2015, subject to certain conditions, at our request, and with the approval of the lenders, the aggregate commitments under the Partnership Credit Agreement could be increased by up to an additional $50 million.
The Partnership Credit Agreement contains various covenants with which the Partnership must comply, including, but not limited to, restrictions on the use of proceeds from borrowings and limitations on the Partnership’s ability to incur additional indebtedness, engage in transactions with affiliates, merge or consolidate, sell assets, make certain investments and acquisitions, make loans, grant liens, repurchase equity and pay dividends and distributions. The Partnership Credit Agreement also contains various covenants requiring mandatory prepayments from the net cash proceeds of certain asset transfers. The Partnership must maintain various consolidated financial ratios, including a ratio of EBITDA (as defined in the Partnership Credit Agreement) to Total Interest Expense (as defined in the Partnership Credit Agreement) of not less than 2.75 to 1.0, a ratio of Total Debt (as defined in the Partnership Credit Agreement) to EBITDA of not greater than 5.25 to 1.0 (subject to a temporary increase to 5.5 to 1.0 for any quarter during which an acquisition meeting certain thresholds is completed and for the following two quarters after the acquisition closes) and a ratio of Senior Secured Debt (as defined in the Partnership Credit Agreement) to EBITDA of not greater than 4.0 to 1.0. Because the Partnership completed an acquisition meeting certain thresholds during the second quarter of 2015 (see Note 19 (“Transactions Related to the Partnership”) for further discussion), the Partnership’s Total Debt to EBITDA ratio threshold was temporarily increased to 5.5 to 1.0 during the quarter ended June 30, 2015 and continued at that level through December 31, 2015, reverting to 5.25 to 1.0 for the quarter ending March 31, 2016 and subsequent quarters. A material adverse effect with respect to the Partnership’s assets, liabilities, financial condition, business or operations that, taken as a whole, impacts the Partnership’s ability to perform its obligations under the Partnership Credit Agreement, could lead to a default under that agreement. A default under one of the Partnership’s debt agreements would trigger cross-default provisions under the Partnership’s other debt agreements, which would accelerate the Partnership’s obligation to repay its indebtedness under those agreements. As of December 31, 2015, the Partnership was in compliance with all financial covenants under the Partnership Credit Agreement.
The Partnership 6% Senior Notes Due April 2021
In March 2013, the Partnership issued $350.0 million aggregate principal amount of 6% senior notes due April 2021 (the “Partnership 2013 Notes”). The Partnership used the net proceeds of $336.9 million, after original issuance discount and issuance costs, to repay borrowings outstanding under its revolving credit facility. The Partnership incurred $7.8 million in transaction costs related to this issuance. These costs were included in intangible and other assets, net, and are being amortized to interest expense over the term of the Partnership 2013 Notes. The Partnership 2013 Notes were issued at an original issuance discount of $5.5 million, which is being amortized using the effective interest method at an interest rate of 6.25% over their term. During the years ended December 31, 2015, 2014 and 2013, the Partnership recognized $0.6 million, $0.5 million and $0.4 million, respectively, of interest expense related to amortization of the debt discount. In January 2014, holders of the Partnership 2013 Notes exchanged their Partnership 2013 Notes for registered notes with the same terms.
The Partnership 2013 Notes are guaranteed on a senior unsecured basis by all of the Partnership’s existing subsidiaries (other than Archrock Partners Finance Corp. (“APLP Finance Corp.”), which is a co-issuer of the Partnership 2013 Notes) and certain of the Partnership’s future subsidiaries. The Partnership 2013 Notes and the guarantees, respectively, are the Partnership’s and the guarantors’ general unsecured senior obligations, rank equally in right of payment with all of the Partnership’s and the guarantors’ other senior obligations, and are effectively subordinated to all of the Partnership’s and the guarantors’ existing and future secured debt to the extent of the value of the collateral securing such indebtedness. In addition, the Partnership 2013 Notes and guarantees are effectively subordinated to all existing and future indebtedness and other liabilities of any future non-guarantor subsidiaries.
F-24
Prior to April 1, 2017, the Partnership may redeem all or a part of the Partnership 2013 Notes at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make-whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. In addition, the Partnership may redeem up to 35% of the aggregate principal amount of the Partnership 2013 Notes prior to April 1, 2016 with the net proceeds of one or more equity offerings at a redemption price of 106.00% of the principal amount of the Partnership 2013 Notes, plus any accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the Partnership 2013 Notes issued under the indenture remains outstanding after such redemption and the redemption occurs within 180 days of the date of the closing of such equity offering. On or after April 1, 2017, the Partnership may redeem all or a part of the Partnership 2013 Notes at redemption prices (expressed as percentages of principal amount) equal to 103.00% for the twelve-month period beginning on April 1, 2017, 101.500% for the twelve-month period beginning on April 1, 2018 and 100.00% for the twelve-month period beginning on April 1, 2019 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the Partnership 2013 Notes.
The Partnership 6% Senior Notes Due October 2022
In April 2014, the Partnership issued $350.0 million aggregate principal amount of the Partnership 2014 Notes. The Partnership received net proceeds of $337.4 million, after original issuance discount and issuance costs, from this offering, which it used to fund a portion of the April 2014 MidCon Acquisition and repay borrowings under its revolving credit facility. The Partnership incurred $6.9 million in transaction costs related to this issuance. These costs were included in intangible and other assets, net, and are being amortized to interest expense over the term of the Partnership 2014 Notes. The Partnership 2014 Notes were issued at an original issuance discount of $5.7 million, which is being amortized using the effective interest method at an interest rate of 6.25% over their term. During the years ended December 31, 2015 and 2014, the Partnership recognized $0.6 million and $0.5 million, respectively, of interest expense related to amortization of the debt discount. In February 2015, holders of the Partnership 2014 Notes exchanged their Partnership 2014 Notes for registered notes with the same terms.
The Partnership 2014 Notes are guaranteed on a senior unsecured basis by all of the Partnership’s existing subsidiaries (other than APLP Finance Corp., which is a co-issuer of the Partnership 2014 Notes) and certain of the Partnership’s future subsidiaries. The Partnership 2014 Notes and the guarantees, respectively, are the Partnership’s and the guarantors’ general unsecured senior obligations, rank equally in right of payment with all of the Partnership’s and the guarantors’ other senior obligations, and are effectively subordinated to all of the Partnership’s and the guarantors’ existing and future secured debt to the extent of the value of the collateral securing such indebtedness. In addition, the Partnership 2014 Notes and guarantees are effectively subordinated to all existing and future indebtedness and other liabilities of any future non-guarantor subsidiaries.
Prior to April 1, 2018, the Partnership may redeem all or a part of the Partnership 2014 Notes at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make-whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. In addition, the Partnership may redeem up to 35% of the aggregate principal amount of the Partnership 2014 Notes prior to April 1, 2017 with the net proceeds of one or more equity offerings at a redemption price of 106.00% of the principal amount of the Partnership 2014 Notes, plus any accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the Partnership 2014 Notes issued under the indenture remains outstanding after such redemption and the redemption occurs within 180 days of the date of the closing of such equity offering. On or after April 1, 2018, the Partnership may redeem all or a part of the Partnership 2014 Notes at redemption prices (expressed as percentages of principal amount) equal to 103.00% for the twelve-month period beginning on April 1, 2018, 101.500% for the twelve-month period beginning on April 1, 2019 and 100.00% for the twelve-month period beginning on April 1, 2020 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date of the Partnership 2014 Notes.
7.25% Senior Notes
On December 4, 2015, we redeemed for cash the $350.0 million aggregate principal amount of 7.25% senior notes due December 2018 (the “7.25% Notes”) at a redemption price equal to 101.813% of the principal amount thereof plus accrued but unpaid interest to the redemption date for $369.2 million. Upon redemption, the 7.25% Notes were no longer deemed outstanding, interest ceased to accrue thereon and all rights of the holders of the 7.25% Notes ceased to exist. We financed the redemption of the 7.25% Notes through borrowings under our revolving credit facility. As a result of the redemption, we expensed the $6.3 million call premium and $2.9 million of unamortized deferred financing costs associated with the notes in the fourth quarter of 2015, which is reflected in debt extinguishment costs in our consolidated statements of operations.
F-25
4.25% Convertible Senior Notes
In June 2009, we issued $355.0 million aggregate principal amount of 4.25% convertible senior notes due June 2014 (the “4.25% Notes”). The 4.25% Notes, after taking into consideration dividends declared, were convertible upon the occurrence of certain conditions into shares of our common stock at a conversion rate of 43.5084 shares of our common stock per $1,000 principal amount of the convertible notes, equivalent to a conversion price of approximately $22.98 per share of common stock. In June 2014, we completed our redemption of the 4.25% Notes in exchange for $370.0 million in cash and 6.8 million shares of our common stock.
GAAP requires that the liability and equity components of certain convertible debt instruments that may be settled in cash upon conversion be separately accounted for in a manner that reflects an issuer’s nonconvertible debt borrowing rate. Upon issuance of our 4.25% Notes, $97.9 million was recorded as a debt discount and reflected in equity related to the convertible feature of these notes. The discount on the 4.25% Notes was amortized using the effective interest method through June 30, 2014. During the years ended December 31, 2014 and 2013, we recognized $6.9 million and $15.1 million of interest expense related to the contractual interest coupon, respectively. During the years ended December 31, 2014 and 2013, we recognized $11.3 million and $23.0 million, respectively, of interest expense related to the amortization of the debt discount. The effective interest rate on the debt component of these notes was 11.67%.
In connection with the offering of the 4.25% Notes, we purchased call options on our stock at approximately $22.98 per share of common stock, after taking into consideration dividends declared, and sold warrants on our stock at approximately $32.19 per share of common stock, after taking into consideration dividends declared. These transactions economically adjust the effective conversion price to $32.19 for $325.0 million of the 4.25% Notes. In June 2014, we exercised our call options to acquire 6.5 million shares of our common stock. The cost of the common shares acquired was recorded as treasury stock in our consolidated balance sheets based on the original cost of the call options of $89.4 million. Counterparties to our warrants had the right to exercise the warrants in equal installments for 80 trading days which began in September 2014. During the year ended December 31, 2014, 1.6 million common shares were issued out of treasury stock pursuant to warrants exercised.
Debt Compliance
We were in compliance with our debt covenants as of December 31, 2015. If we fail to remain in compliance with our financial covenants we would be in default under our credit agreements. In addition, if we experience a material adverse effect on our assets, liabilities, financial condition, business or operations that, taken as a whole, impact our ability to perform our obligations under our debt agreements, this could lead to a default under our debt agreements. A default under one or more of our debt agreements would trigger cross-default provisions under certain of our other debt agreements, which would accelerate our obligation to repay our indebtedness under those agreements.
Long-Term Debt Maturity Schedule
Contractual maturities of long-term debt (excluding interest to be accrued thereon) at December 31, 2015 are as follows (in thousands):
December 31, 2015 | |||
2016 | $ | — | |
2017 | — | ||
2018 | 730,500 | ||
2019 | — | ||
2020 | 166,500 | ||
Thereafter (1) | 700,000 | ||
Total debt (1) | $ | 1,597,000 | |
(1) | These amounts include the full face value of the Partnership 2013 Notes and the Partnership 2014 Notes and have not been reduced by the aggregate unamortized discount of $8.6 million as of December 31, 2015. |
F-26
10. Accounting for Derivatives
We are exposed to market risks associated with changes in interest rates. We use derivative financial instruments to minimize the risks and/or costs associated with financial activities by managing our exposure to interest rate fluctuations on a portion of our debt obligations. We do not use derivative financial instruments for trading or other speculative purposes.
Interest Rate Risk
During the year ended December 31, 2015, the Partnership entered into an interest rate swap with a notional value of $100.0 million. At December 31, 2015, the Partnership was a party to interest rate swaps with a total notional value of $500.0 million, pursuant to which it makes fixed payments and receives floating payments. The Partnership entered into these swaps to offset changes in expected cash flows due to fluctuations in the associated variable interest rates. The Partnership’s interest rate swaps expire over varying dates, with interest rate swaps having a notional amount of $300.0 million expiring in May 2018, interest rate swaps having a notional amount of $100.0 million expiring in May 2019 and the remaining interest rate swaps having a notional amount of $100.0 million expiring in May 2020. As of December 31, 2015, the weighted average effective fixed interest rate on the interest rate swaps was 1.6%. We have designated these interest rate swaps as cash flow hedging instruments so that any change in their fair values is recognized as a component of comprehensive income (loss) and is included in accumulated other comprehensive income (loss) to the extent the hedge is effective. As the swap terms substantially coincide with the hedged item and are expected to offset changes in expected cash flows due to fluctuations in the variable rate, we currently do not expect a significant amount of ineffectiveness on these hedges. We perform quarterly calculations to determine whether the swap agreements are still effective and to calculate any ineffectiveness. We recorded $0.4 million of interest income during the year ended December 31, 2015 due to ineffectiveness related to interest rate swaps. There was no ineffectiveness related to interest rate swaps during the years ended December 31, 2014 and 2013. We estimate that $3.5 million of deferred pre-tax losses attributable to interest rate swaps and included in our accumulated other comprehensive income (loss) at December 31, 2015, will be reclassified into earnings as interest expense at then current values during the next twelve months as the underlying hedged transactions occur. Cash flows from derivatives designated as hedges are classified in our consolidated statements of cash flows under the same category as the cash flows from the underlying assets, liabilities or anticipated transactions, unless the derivative contract contains a significant financing element; in this case, the cash settlements for these derivatives are classified as cash flows from financing activities in our consolidated statements of cash flows.
In May 2013, the Partnership amended its interest rate swap agreements with a notional value of $250.0 million to adjust the fixed interest rates and extend the maturity dates to May 2018 consistent with the maturity date of the Partnership Credit Agreement. These amendments effectively created new derivative contracts and terminated the old derivative contracts. As a result, we designated the new hedge relationships under the amended terms and de-designated the original hedge relationships as of the termination date. The original hedge relationships qualified for hedge accounting and were included at their fair value in our consolidated balance sheet as a liability and accumulated other comprehensive income (loss). The fair value of the interest rate swap agreements immediately prior to the execution of the amendments was a liability of $8.8 million. The associated amount in accumulated other comprehensive income (loss) was being amortized into interest expense through November 2015.
The following tables present the effect of derivative instruments on our consolidated financial position and results of operations (in thousands):
December 31, 2015 | December 31, 2014 | |||||||
Balance Sheet Location | Fair Value Asset (Liability) | Fair Value Asset (Liability) | ||||||
Derivatives designated as hedging instruments: | ||||||||
Interest rate swaps | Intangible and other assets, net | $ | 45 | $ | 712 | |||
Interest rate swaps | Accrued liabilities | (4,608 | ) | (4,958 | ) | |||
Interest rate swaps | Other long-term liabilities | (1,421 | ) | (150 | ) | |||
Total derivatives | $ | (5,984 | ) | $ | (4,396 | ) | ||
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Pre-tax Gain (Loss) Recognized in Other Comprehensive Income (Loss) on Derivatives | Location of Pre-tax Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Income (Loss) | Pre-tax Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Income (Loss) | |||||||
Derivatives designated as cash flow hedges: | |||||||||
Interest rate swaps | |||||||||
Year ended December 31, 2015 | $ | (8,901 | ) | Interest expense | $ | (7,259 | ) | ||
Year ended December 31, 2014 | (5,879 | ) | Interest expense | (5,657 | ) | ||||
Year ended December 31, 2013 | 3,057 | Interest expense | (6,124 | ) | |||||
The counterparties to the derivative agreements are major international financial institutions. We monitor the credit quality of these financial institutions and do not expect non-performance by any counterparty, although such non-performance could have a material adverse effect on us. The Partnership has no specific collateral posted for its derivative instruments. The counterparties to the interest rate swaps are also lenders under the Partnership’s senior secured credit facility and, in that capacity, share proportionally in the collateral pledged under the related facility.
11. Fair Value Measurements
The accounting standard for fair value measurements and disclosures establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into the following three broad categories:
• | Level 1 — Quoted unadjusted prices for identical instruments in active markets to which we have access at the date of measurement. |
• | Level 2 — Quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets. Level 2 inputs are those in markets for which there are few transactions, the prices are not current, little public information exists or prices vary substantially over time or among brokered market makers. |
• | Level 3 — Model derived valuations in which one or more significant inputs or significant value drivers are unobservable. Unobservable inputs are those inputs that reflect our own assumptions regarding how market participants would price the asset or liability based on the best available information. |
The following table presents our assets and liabilities measured at fair value on a recurring basis as of December 31, 2015 and 2014, with pricing levels as of the date of valuation (in thousands):
December 31, 2015 | December 31, 2014 | ||||||||||||||||||||||
(Level 1) | (Level 2) | (Level 3) | (Level 1) | (Level 2) | (Level 3) | ||||||||||||||||||
Interest rate swaps asset | $ | — | $ | 45 | $ | — | $ | — | $ | 712 | $ | — | |||||||||||
Interest rate swaps liability | — | (6,029 | ) | — | — | (5,108 | ) | — | |||||||||||||||
On a quarterly basis, the interest rate swaps are recorded at fair value utilizing a combination of the market approach and income approach to estimate fair value based on forward LIBOR curves.
The following table presents our assets and liabilities measured at fair value on a nonrecurring basis during the years ended December 31, 2015 and 2014, with pricing levels as of the date of valuation (in thousands):
December 31, 2015 | December 31, 2014 | ||||||||||||||||||||||
(Level 1) | (Level 2) | (Level 3) | (Level 1) | (Level 2) | (Level 3) | ||||||||||||||||||
Impaired long-lived assets | $ | — | $ | — | $ | 12,565 | $ | — | $ | — | $ | 3,359 | |||||||||||
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Our estimate of the impaired long-lived assets’ fair value was primarily based on either the expected net sale proceeds compared to other fleet units we recently sold and/or a review of other units recently offered for sale by third parties, or the estimated component value of the equipment we plan to use. We discounted the expected proceeds, net of selling and other carrying costs, using a weighted average disposal period of four years and a weighted average discount rate of 12% and 9% for the years ended December 31, 2015 and 2014, respectively.
12. Long-Lived Asset Impairment
During the year ended December 31, 2015, we reviewed the future deployment of our idle compression assets used in our contract operations segment for units that were not of the type, configuration, condition, make or model that are cost efficient to maintain and operate. Based on this review, we determined that approximately 900 idle compressor units totaling approximately 371,000 horsepower would be retired from the active fleet during the year ended December 31, 2015. The retirement of these units from the active fleet triggered a review of these assets for impairment. As a result, we recorded a $111.7 million asset impairment to reduce the book value of each unit to its estimated fair value during the year ended December 31, 2015. The fair value of each unit was estimated based on either the expected net sale proceeds compared to other fleet units we recently sold and/or a review of other units recently offered for sale by third parties, or the estimated component value of the equipment we plan to use.
In connection with our fleet review during the year ended December 31, 2015, we evaluated for impairment idle units that had been culled from our fleet in prior years and were available for sale. Based upon that review, we reduced the expected proceeds from disposition for certain of the remaining units. This resulted in an additional impairment of $13.3 million during the year ended December 31, 2015 to reduce the book value of each unit to its estimated fair value.
During the year ended December 31, 2014, we evaluated the future deployment of our idle fleet and determined to retire and either sell or re-utilize the key components of approximately 290 idle compressor units, representing approximately 112,000 horsepower, previously used to provide services in our contract operations segment. As a result, we performed an impairment review and recorded a $30.4 million asset impairment to reduce the book value of each unit to its estimated fair value. The fair value of each unit was estimated based on either the expected net sale proceeds compared to other fleet units we recently sold and/or a review of other units recently offered for sale by third parties, or the estimated component value of the equipment we plan to use.
In connection with our fleet review during 2014, we evaluated for impairment idle units that had been culled from our fleet in prior years and were available for sale. Based upon that review, we reduced the expected proceeds from disposition for certain of the remaining units. This resulted in an additional impairment of $11.7 million to reduce the book value of each unit to its estimated fair value.
During the year ended December 31, 2014, we evaluated other long-lived assets for impairment and recorded long-lived asset impairments of $0.7 million on these assets.
During the year ended December 31, 2013, we evaluated the future deployment of our idle fleet and determined to retire and either sell or re-utilize the key components of approximately 280 idle compressor units, representing approximately 76,000 horsepower, previously used to provide services in our contract operations segment. As a result, we performed an impairment review and recorded a $14.9 million asset impairment to reduce the book value of each unit to its estimated fair value. The fair value of each unit was estimated based on either the expected net sale proceeds compared to other fleet units we recently sold and/or a review of other units recently offered for sale by third parties, or the estimated component value of the equipment we plan to use.
During the year ended December 31, 2013, we evaluated other long-lived assets for impairment and recorded long-lived asset impairments of $1.8 million on these assets.
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13. Restructuring Charges
As discussed in Note 2 (“Discontinued Operations”), we completed the Spin-off of Exterran Corporation on November 3, 2015. During the year ended December 31, 2015, we incurred $4.1 million of costs associated with the Spin-off which were directly attributable to Archrock and are summarized below. The restructuring charges associated with the Spin-off have not been allocated to the segments because they primarily represent costs incurred within the corporate function. Restructuring charges incurred in 2015 and 2014 in conjunction with completion of the Spin-off or directly associated with the Exterran Corporation business are included in discontinued operations in our consolidated statements of operations. As of December 31, 2015, we had an accrued liability balance of $0.9 million for retention and severance benefits incurred. We expect to incur an additional $2.0 million in both 2016 and 2017 related to retention payments.
In the second quarter of 2015 we announced a cost reduction plan primarily focused on workforce reductions. During the year ended December 31, 2015, we incurred $0.6 million of restructuring and other charges as a result of this plan primarily related to termination benefits. These charges are reflected as restructuring and other charges in our consolidated statement of operations.
In January 2014, we announced a plan to centralize our make-ready operations to improve the cost and efficiency of our shops and further enhance the competitiveness of our fleet of compressors. As part of this plan, we examined both recent and anticipated changes in the U.S. market, including the throughput demand of our shops and the addition of new equipment to our fleet. To better align our costs and capabilities with the current market, we determined to close several of our make-ready shops. The centralization of our make-ready operations was completed in the second quarter of 2014.
The following table summarizes the changes to our accrued liability balance related to restructuring charges for the year ended December 31, 2015 and December 31, 2014 (in thousands):
Spin-off | Cost Reduction Plan | Total | |||||||||
Balance at January 1, 2014 | $ | — | $ | — | $ | — | |||||
Additions for costs expensed | — | 5,394 | 5,394 | ||||||||
Less: non-cash expense | — | (4,103 | ) | (4,103 | ) | ||||||
Reductions for payments | — | (1,291 | ) | (1,291 | ) | ||||||
Balance at January 1, 2015 | $ | — | $ | — | $ | — | |||||
Additions for costs expensed | 4,135 | 610 | 4,745 | ||||||||
Less: non-cash expense | (2,515 | ) | $ | — | (2,515 | ) | |||||
Reductions for payments | (765 | ) | (610 | ) | (1,375 | ) | |||||
Balance at December 31, 2015 | $ | 855 | $ | — | $ | 855 | |||||
The following table summarizes the components of charges included in restructuring and other charges in our consolidated statements of operations for the year ended December 31, 2015 and December 31, 2014 (in thousands):
Year ended December 31, 2015 | Year ended December 31, 2014 | ||||||
Retention and severance benefits | $ | 3,135 | $ | — | |||
Non-cash inventory write-downs | 1,000 | 4,103 | |||||
Employee termination benefits | 610 | 1,291 | |||||
Total restructuring and other charges | $ | 4,745 | $ | 5,394 | |||
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14. Income Taxes
The provision for (benefit from) income taxes consisted of the following (in thousands):
Years Ended December 31, | |||||||||||
2015 | 2014 | 2013 | |||||||||
Current tax provision (benefit): | |||||||||||
U.S. federal | $ | 556 | $ | 23 | $ | (310 | ) | ||||
State | 1,415 | (654 | ) | 938 | |||||||
Total current | 1,971 | (631 | ) | 628 | |||||||
Deferred tax provision (benefit): | |||||||||||
U.S. federal | 48,450 | (23,786 | ) | (18,397 | ) | ||||||
State | 2,768 | (3,649 | ) | (71 | ) | ||||||
Total deferred | 51,218 | (27,435 | ) | (18,468 | ) | ||||||
Provision for (benefit from) income taxes | $ | 53,189 | $ | (28,066 | ) | $ | (17,840 | ) | |||
The provision for (benefit from) income taxes for 2015, 2014 and 2013 resulted in effective tax rates on continuing operations of (50.1)%, 62.1% and 85.4%, respectively. The reasons for the differences between these effective tax rates and the U.S. statutory rate of 35% are as follows (in thousands):
Years Ended December 31, | |||||||||||
2015 | 2014 | 2013 | |||||||||
Income taxes at U.S. federal statutory rate of 35% | $ | (37,165 | ) | $ | (15,813 | ) | $ | (7,311 | ) | ||
Net state income taxes | 2,383 | (5,253 | ) | 937 | |||||||
Noncontrolling interest | (2,904 | ) | (11,166 | ) | (12,685 | ) | |||||
Unrecognized tax benefits | 698 | 4,063 | 416 | ||||||||
Valuation allowances and write off of tax attributes | 88,088 | — | — | ||||||||
Other | 2,089 | 103 | 803 | ||||||||
Provision for (benefit from) income taxes | $ | 53,189 | $ | (28,066 | ) | $ | (17,840 | ) | |||
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Deferred income tax balances are the direct effect of temporary differences between the financial statement carrying amounts and the tax basis of assets and liabilities at the enacted tax rates expected to be in effect when the taxes are actually paid or recovered. The tax effects of temporary differences that give rise to deferred tax assets and deferred tax liabilities are as follows (in thousands):
December 31, | |||||||
2015 | 2014 | ||||||
Deferred tax assets: | |||||||
Net operating loss carryforwards | $ | 8,028 | $ | 37,668 | |||
Inventory | 3,642 | 4,405 | |||||
Alternative minimum tax credit carryforwards | 1,496 | 5,685 | |||||
Accrued liabilities | 11,466 | 7,894 | |||||
Other | 4,913 | — | |||||
Subtotal | 29,545 | 55,652 | |||||
Valuation allowances | (633 | ) | (633 | ) | |||
Total deferred tax assets | 28,912 | 55,019 | |||||
Deferred tax liabilities: | |||||||
Property, plant and equipment | (53,495 | ) | (126,670 | ) | |||
Basis difference in the Partnership | (148,421 | ) | (136,438 | ) | |||
Other | (5,562 | ) | (10,583 | ) | |||
Total deferred tax liabilities | (207,478 | ) | (273,691 | ) | |||
Net deferred tax liabilities | $ | (178,566 | ) | $ | (218,672 | ) | |
Tax balances are presented in the accompanying consolidated balance sheets as deferred income taxes.
Pursuant to Sections 382 and 383 of the Internal Revenue Code of 1986, as amended, utilization of loss carryforwards and alternative minimum tax credits, are subject to annual limitations due to any ownership changes of 5% owners. In general, an ownership change, as defined by Section 382, results from transactions increasing the ownership of certain stockholders or public groups in the stock of a corporation by more than 50 percentage points over a three-year period. The Hanover/Universal merger in 2007 resulted in such an ownership change but the Spin-off did not result in such an ownership change for Archrock. Our ability to utilize loss carryforwards and credit carryforwards against future U.S. federal taxable income and future U.S. federal income tax may be limited in the future if we have another 50% or more ownership change in our 5% shareholders. The limitations may cause us to pay U.S. federal income taxes earlier; however, we do not currently expect that any loss carryforwards or credit carryforwards will expire as a result of any 382 or 383 limitations.
On September 13, 2013, the U.S. Treasury Department and the IRS issued final regulations that address costs incurred in acquiring, producing, or improving tangible property (the “tangible property regulations”). The tangible property regulations are generally effective for tax years beginning on or after January 1, 2014. The tangible property regulations required us to make tax accounting method changes and file election statements with our U.S. federal tax return for our tax year beginning on January 1, 2014; however, these new requirements did not have a material impact on our consolidated financial statements.
At December 31, 2015, we had U.S. federal and state net operating loss (“NOL”) carryforwards of approximately $22.0 million and $6.7 million, respectively, included in our NOL deferred tax asset that are available to offset future taxable income. If not used, the federal and state carryforwards will begin to expire in 2025 and 2020, respectively. Alternative minimum tax credit carryforwards of $1.5 million are available to offset future payments of U.S. federal income tax and may be carried forward indefinitely under current U.S. tax law.
Employee share-based compensation attributable to the exercise of stock options and vesting of restricted stock is deductible by us for tax purposes. For post-2005 tax years, to the extent these tax deductions exceed the previously accrued deferred tax benefit for these items the additional tax benefit is not recognized under GAAP until the deduction reduces current taxes payable. For pre-2006 tax years, (prior to the adoption of ASC 718, formerly known as FAS 123R), the additional tax benefit is included in our NOL deferred tax asset with a corresponding valuation allowance negating the benefit. At December 31, 2015, the post-2005 tax benefit not included in our NOL deferred tax asset is $581,000 and the pre-2006 tax benefit included in our NOL deferred tax asset with an offsetting valuation allowance is $633,000.
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We record valuation allowances when it is more likely than not that some portion or all of our deferred tax assets will not be realized. The ultimate realization of the deferred tax assets depends on the ability to generate sufficient taxable income of the appropriate character and in the appropriate taxing jurisdictions in the future. If we do not meet our expectations with respect to taxable income, we may not realize the full benefit from our deferred tax assets which would require us to record a valuation allowance in our tax provision in future years.
At the time of the Spin-off we had recorded $144.3 million in foreign tax credit deferred tax assets. These deferred tax assets related to foreign tax credits that can be used to reduce our income taxes payable in the current and future years. They will expire if they are not used within the 10-year carryforward period. As a result of the Spin-off it is projected that these Foreign tax credits/deductions allocated to Exterran Corporation will expire unused because Exterran Corporation will not generate sufficient taxable income and foreign source taxable income after the Spin-off to utilize these credits. Therefore, in the fourth quarter, we wrote off foreign tax credits for the years 2005-2010 in the amount of $48.2 million and set up a valuation allowance for the years 2011-2015 of $37.8 million for a total impact to Archrock’s fourth quarter tax provision of $86.0 million. The credits and offsetting valuation allowance were allocated to Exterran Corporation for their use in future tax returns.
A reconciliation of the beginning and ending amount of unrecognized tax benefits (including discontinued operations) is shown below (in thousands):
Years Ended December 31, | |||||||||||
2015 | 2014 | 2013 | |||||||||
Beginning balance | $ | 14,595 | $ | 11,259 | $ | 9,597 | |||||
Additions based on tax positions related to current year | 845 | 954 | 365 | ||||||||
Additions based on tax positions related to prior years | 3,648 | 2,597 | 1,710 | ||||||||
Reductions based on settlement with government authority | — | — | — | ||||||||
Reductions based on lapse of statute of limitations | — | (215 | ) | (97 | ) | ||||||
Reductions based on tax positions related to prior years | (592 | ) | — | (316 | ) | ||||||
Reductions based on tax positions transferred to Exterran Corp. | (6,498 | ) | $ | — | $ | — | |||||
Ending balance | $ | 11,998 | $ | 14,595 | $ | 11,259 | |||||
We had $12.0 million, $14.6 million and $11.3 million of unrecognized tax benefits at December 31, 2015, 2014 and 2013, respectively, which if recognized, would affect the effective tax rate (except for amounts that would be reflected in income from discontinued operations, net of tax). We also have recorded $0.2 million, $3.3 million and $3.4 million of potential interest expense and penalties related to unrecognized tax benefits associated with uncertain tax positions (including discontinued operations) as of December 31, 2015, 2014 and 2013, respectively. To the extent interest and penalties are not assessed with respect to uncertain tax positions, amounts accrued will be reduced and reflected as reductions in income tax expense.
Subject to the provisions of the tax matters agreement between Exterran Corporation and us, both parties agreed to indemnify the primary obligor of any return for tax periods beginning before and ending before or after the Spin-off (including any ongoing or future amendments and audits for these returns) for the portion of the tax liability (including interest and penalties) that relates to their respective operations reported in the filing. As of December 31, 2015, we have recorded a $5.7 million indemnification asset (including penalties and interest) related to unrecognized tax benefits.
We and our subsidiaries file consolidated and separate income tax returns in the U.S. federal jurisdiction and in numerous state jurisdictions. We are subject to U.S. federal income tax examinations for tax years beginning from 1997 onward and, early in the second quarter of 2011, the Internal Revenue Service (“IRS”) commenced an examination of our U.S. federal income tax returns for the tax years 2006, 2008 and 2009. In October 2012, the IRS completed its examination and issued Revenue Agent’s Reports (“RARs”) that reflected an aggregate over-assessment of $0.9 million. All of the adjustments proposed in the RARs were agreed, except for the disallowance of our telephone excise tax refund (“TETR”) claims of $0.5 million related to the 2006 tax year, for which we filed protests with the Appeals Division of the IRS. We settled with the IRS Appeals Division in December 2013 for more than 90% of our TETR claims and received refunds in the first quarter of 2014. The $0.9 million over-assessment was approved for refund by the Joint Committee on Taxation and was received in the third quarter of 2014. We do not expect any tax adjustments from later tax years that would have a material impact on our conaolidated financial position or consolidated results of operations.
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State income tax returns are generally subject to examination for a period of three to five years after filing the returns. However, the state impact of any U.S. federal audit adjustments and amendments remains subject to examination by various states for up to one year after formal notification to the states. As of December 31, 2015, we did not have any state audits underway that we believe would have a material impact on our consolidated financial position or consolidated results of operations.
We do not believe any of our unrecognized tax benefits will be reduced before the year ended December 31, 2016 due to the settlement of audits and the expiration of statutes of limitations. However, due to the uncertain and complex application of tax regulations, it is possible that the ultimate resolution of these matters may result in liabilities which could materially differ from these estimates.
15. Common Stockholders’ Equity
The Archrock, Inc. (formerly Exterran Holdings, Inc.) 2013 Stock Incentive Plan (the “2013 Plan”) allows us to withhold shares to use upon vesting of restricted stock at the then current market price to cover taxes required to be withheld on the vesting date. We purchased 137,994 of our shares from participants for approximately $4.0 million during 2015 to cover tax withholding. The 2013 Plan is administered by the compensation committee of our board of directors.
16. Stock-Based Compensation and Awards
During the years ended December 31, 2015, 2014 and 2013 we recognized stock based compensation expense in our results of operations of $10.0 million, $12.8 million and $9.0 million, respectively, related to stock options, restricted stock units, performance units, phantom units and the employee stock purchase plan.
Stock Incentive Plan
In April 2013, we adopted the 2013 Plan to provide for the granting of stock options, restricted stock, restricted stock units, stock appreciation rights, performance units, other stock-based awards and dividend equivalent rights to directors of Archrock and employees and consultants of Archrock and its affiliates. Under the 2013 Plan, the maximum number of shares of common stock available for issuance pursuant to awards is 6,500,000. Each option and stock appreciation right granted counts as one share against the aggregate share limit, and any share subject to a stock settled award other than a stock option, stock appreciation right or other award for which the recipient pays intrinsic value counts as 1.75 shares against the aggregate share limit. Shares subject to awards granted under the 2013 Plan that are subsequently canceled, terminated, settled in cash or forfeited (excluding shares withheld to satisfy tax withholding obligations to or pay the exercise price of an option) are, to the extent of such cancelation, termination, settlement or forfeiture, available for future grant under the 2013 Plan. Cash settled awards are not counted against the aggregate share limit. No additional grants may be made under the Archrock, Inc. 2007 Amended and Restated Stock Incentive Plan (the “2007 Plan”). Previous grants made under the 2007 Plan will continue to be governed by their respective plans.
Exterran Corporation Spin-off Adjustments
In connection with the Spin-off of Exterran Corporation, stock options, restricted stock, restricted stock units and performance unit awards were adjusted in accordance with anti-dilution provisions under the existing plans. As such, we did not record any additional compensation expense related to the adjustment of the awards. The awards were generally adjusted as follows:
• | Pre-2015 Awards. Immediately prior to the Spin-off, each outstanding Exterran Holdings stock option, restricted stock, restricted stock unit and performance unit granted prior to January 1, 2015, whether vested or unvested, was split into two awards, consisting of an Archrock award and an Exterran Corporation award. However, Exterran Holdings “incentive stock options” (within the meaning of Section 422 of the Code) were converted solely, into options denominated in shares of common stock of the applicable holder’s post-spin employer if the holder of the award elected, prior to the Spin-off, to preserve the tax treatment of such option. |
• | 2015 Awards. Each Exterran Holdings stock option, restricted stock award, restricted stock unit award and performance unit award that was (i) granted in calendar year 2015 and (ii) held by an individual who became our employee or is engaged to provide service to us following the Spin-off was converted solely into an Archrock award. We did not grant any stock options in the calendar year 2015 prior to the Spin-off. |
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Equity awards that were adjusted as described above generally remain subject to the same vesting, expiration, performance conditions and other terms and conditions as applied to the awards immediately prior to the Spin-off.
Stock Options
Stock options are granted at fair market value at the grant date, are exercisable according to the vesting schedule established by the compensation committee of our board of directors in its sole discretion and expire no later than 7 years after the grant date. Stock options generally vest one-third per year on each of the first three anniversaries of the grant date, subject to continued services through the applicable vesting date.
During the year ended December 31, 2015 we did not grant any stock options. The weighted average grant date fair value for stock options granted during the years ended December 31, 2014 and 2013 was $14.47 and $10.19, respectively, and was estimated using the Black-Scholes option valuation model with the following weighted average assumptions:
Years Ended December 31, | |||||
2014 | 2013 | ||||
Expected life in years | 4.5 | 4.5 | |||
Risk-free interest rate | 1.33 | % | 0.66 | % | |
Volatility | 46.51 | % | 49.19 | % | |
Dividend yield | 1.5 | % | 0.0 | % | |
The risk-free interest rate is based on the U.S. Treasury yield curve in effect on the grant date for a period commensurate with the estimated expected life of the stock options. Expected volatility is based on the historical volatility of our stock over the period commensurate with the expected life of the stock options and other factors. The dividend yield is based on the current annualized dividend rate in effect during the quarter in which the grant was made. At the time of the stock option grants during the year ended December 31, 2013, we had not historically paid any dividends and did not expect to pay any dividends during the expected life of the stock options.
The following table presents stock option activity during the year ended December 31, 2015:
Stock Options (in thousands) | Weighted Average Exercise Price Per Share (2) | Weighted Average Remaining Life (in years) | Aggregate Intrinsic Value (in thousands) | |||||||||
Options outstanding, January 1, 2015 | 1,495 | $ | 33.39 | |||||||||
Granted | — | — | ||||||||||
Exercised | (90 | ) | 12.29 | |||||||||
Canceled | (300 | ) | 59.91 | |||||||||
Spin-off of Exterran Corporation (1) | 142 | (56.65 | ) | |||||||||
Options outstanding, December 31, 2015 | 1,247 | 18.28 | 2.2 | $ | 278 | |||||||
Options exercisable, December 31, 2015 | 1,118 | 17.97 | 1.9 | 278 | ||||||||
(1) | Reflects adjustment of awards outstanding and the exercise price as a result of the Spin-off. |
(2) | Activity prior to the Spin-off reflects historical exercise price. |
Intrinsic value is the difference between the market value of our stock and the exercise price of each stock option multiplied by the number of stock options outstanding for those stock options where the market value exceeds their exercise price. The total intrinsic value of stock options exercised during 2015, 2014 and 2013 was $1.5 million, $16.6 million and $4.4 million, respectively. As of December 31, 2015, we expect $0.5 million of unrecognized compensation cost related to unvested stock options to be recognized over the weighted-average period of 1.0 years.
F-35
Restricted Stock, Stock-Settled Restricted Stock Units, Performance Units, Cash Settled Restricted Stock Units and Performance Units
For grants of restricted stock, restricted stock units and performance units, we recognize compensation expense over the vesting period equal to the fair value of our common stock at the grant date. Our restricted stock and certain of our restricted stock units and performance units include rights to receive dividends or dividend equivalents. We remeasure the fair value of cash settled restricted stock units and cash-settled performance units and record a cumulative adjustment of the expense previously recognized. Our obligation related to the cash-settled restricted stock units and cash-settled performance units is reflected as a liability in our consolidated balance sheets. Restricted stock, stock-settled restricted stock units, performance units, cash-settled restricted stock units and performance units generally vest one-third per year on each of the first three anniversaries of the grant date, subject to continued services through the applicable vesting date.
The following table presents restricted stock, stock-settled restricted stock unit, performance unit, cash-settled restricted stock unit and cash-settled performance unit activity during the year ended December 31, 2015:
Shares (in thousands) | Weighted Average Grant-Date Fair Value Per Share (3) | |||||
Non-vested awards, January 1, 2015 | 1,170 | $ | 27.37 | |||
Granted | 1,008 | 25.49 | ||||
Vested | (809 | ) | 23.05 | |||
Canceled | (53 | ) | 30.25 | |||
Spin-off of Exterran Corporation (1) | (161 | ) | (99.93 | ) | ||
Non-vested awards, December 31, 2015 (2) | 1,155 | 18.50 | ||||
(1) | Reflects adjustment of outstanding awards in connection with and the grant date fair value adjusted as a result of, the Spin-off. |
(2) | Non-vested awards as of December 31, 2015 are comprised of 55,000 cash settled restricted stock units and cash settled performance units and 1,100,000 restricted shares, stock-settled restricted stock units and performance units. |
(3) | Excluding the Spin-off of Exterran Corporation adjustment, reflects historical grant date fair value. |
As of December 31, 2015, we expect $11.7 million of unrecognized compensation cost related to unvested restricted stock, restricted stock units, performance units, cash settled restricted stock units and cash settled performance units to be recognized over the weighted-average period of 1.8 years.
Employee Stock Purchase Plan
In August 2007, we adopted the Archrock, Inc. Employee Stock Purchase Plan (as amended, the “ESPP”), which is intended to provide employees with an opportunity to participate in our long-term performance and success through the purchase of shares of common stock at a price that may be less than fair market value. The ESPP is designed to comply with Section 423 of the Internal Revenue Code of 1986, as amended. Each quarter, an eligible employee may elect to withhold a portion of his or her salary up to the lesser of $25,000 per year or 10% of his or her eligible pay to purchase shares of our common stock at a price equal to 85% to 100% of the fair market value of the stock as of the first trading day of the quarter, the last trading day of the quarter or the lower of the first trading day of the quarter and the last trading day of the quarter, as the compensation committee of our board of directors may determine. The ESPP will terminate on the date that all shares of common stock authorized for sale under the ESPP have been purchased, unless it is extended. In May 2011, we amended the ESPP to increase the maximum number of shares of common stock available for purchase under the ESPP to 1,000,000. As a result of the Spin-off, the ESPP was suspended after the second quarter 2015 purchase period.
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Directors’ Stock and Deferral Plan
On August 20, 2007, we adopted the Archrock, Inc. Directors’ Stock and Deferral Plan to provide non-employee members of the board of directors with an opportunity to elect to receive our common stock as payment for a portion or all of their retainer and meeting fees. The number of shares paid each quarter is determined by dividing the dollar amount of fees elected to be paid in common stock by the closing sales price per share of the common stock on the last day of the quarter. In addition, directors who elect to receive a portion or all of their fees in the form of common stock may also elect to defer, until a later date, the receipt of a portion or all of their fees to be received in common stock. We have reserved 100,000 shares under the Directors’ Stock and Deferral Plan, and as of December 31, 2015, 48,022 shares remained available to be issued under the plan.
Partnership Long-Term Incentive Plan
The Partnership’s Long-Term Incentive Plan (the “Partnership Plan”) was adopted, in October 2006 for the benefit of the employees, directors and consultants of the Partnership, us and our respective affiliates. A maximum of 1,035,378 common units are available for the issuance of common unit options, restricted units, unit awards and phantom units under the Partnership Plan. The Partnership Plan is administered by the compensation committee of the board of directors of Archrock GP LLC, the general partner of the Partnership’s general partner (the “Partnership Plan Administrator”).
Phantom units are notional units that entitle the grantee to receive common units upon the vesting of such phantom units or, at the discretion of the Partnership Plan Administrator, cash equal to the fair market value of such common units. Phantom units granted under the Partnership Plan may include nonforfeitable tandem distribution equivalent rights to receive cash distributions on unvested phantom units in the quarter in which distributions are paid on common units. Phantom units generally vest one-third per year on each of the first three anniversaries of the grant date, subject to continued service through the applicable vesting date.
Partnership Phantom Units
The following table presents phantom unit activity during the year ended December 31, 2015:
Phantom Units (in thousands) | Weighted Average Grant-Date Fair Value per Unit | |||||
Phantom units outstanding, January 1, 2015 | 92 | $ | 27.38 | |||
Granted | 45 | 24.87 | ||||
Vested | (60 | ) | 25.94 | |||
Phantom units outstanding, December 31, 2015 | 77 | 27.01 | ||||
As of December 31, 2015, we expect $1.2 million of unrecognized compensation cost related to unvested phantom units to be recognized over the weighted-average period of 1.7 years.
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17. Cash Dividends
The following table summarizes our dividends per common share:
Declaration Date | Payment Date | Dividends per Common Share | Total Dividends | |||||||
February 25, 2014 | March 28, 2014 | $ | 0.15 | $ | 10.0 | million | ||||
April 29, 2014 | May 16, 2014 | 0.15 | 10.0 | million | ||||||
July 31, 2014 | August 18, 2014 | 0.15 | 10.0 | million | ||||||
October 30, 2014 | November 17, 2014 | 0.15 | 10.3 | million | ||||||
January 30, 2015 | February 17, 2015 | 0.15 | 10.3 | million | ||||||
April 28, 2015 | May 18, 2015 | 0.15 | 10.4 | million | ||||||
July 30, 2015 | August 17, 2015 | 0.15 | 10.5 | million | ||||||
October 18, 2015 | October 30, 2015 | 0.15 | 10.4 | million | ||||||
On January 26, 2016, our board of directors declared a quarterly dividend of $0.1875 per share of common stock which was paid on February 16, 2016 to stockholders of record at the close of business on February 9, 2016. Any future determinations to pay cash dividends to our stockholders will be at the discretion of our board of directors and will be dependent upon our financial condition and results of operations, credit and loan agreements in effect at that time and other factors deemed relevant by our board of directors.
18. Retirement Benefit Plan
Our 401(k) retirement plan provides for optional employee contributions up to the applicable Internal Revenue Service annual limit and discretionary employer matching contributions. We make discretionary matching contributions to each participant’s account at a rate of (i) 100% of each participant’s first 1% of contributions plus (ii) 50% of each participant’s contributions up to the next 5% of eligible compensation. We recorded matching contributions of $4.2 million, $5.0 million and $4.2 million during 2015, 2014 and 2013, respectively.
19. Transactions Related to the Partnership
In May 2015, the Partnership entered into an At-The-Market Equity Offering Sales Agreement (the “ATM Agreement”) with Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., J.P. Morgan Securities LLC, RBC Capital Markets, LLC and Wells Fargo Securities, LLC (the “Sales Agents”). Pursuant to the ATM Agreement, the Partnership may sell from time to time through the Sales Agents common units representing limited partner interests in the Partnership having an aggregate offering price of up to $100.0 million. Under the terms of the ATM Agreement, the Partnership may also sell common units from time to time to any Sales Agent as principal for its own account at a price to be agreed upon at the time of sale. Any sale of common units to a Sales Agent as principal would be pursuant to the terms of a separate terms agreement between the Partnership and such Sales Agent. The Partnership intends to use the net proceeds of this offering, after deducting the Sales Agents’ commission and its offering expenses, for general partnership purposes, which may include, among other things paying or refinancing a portion of its outstanding debt. During the year ended December 31, 2015, the Partnership sold 49,774 common units for net proceeds of $1.2 million pursuant to the ATM Agreement.
In April 2015, we sold to the Partnership contract operations customer service agreements with 60 customers and a fleet of 238 compressor units used to provide compression services under those agreements, comprising approximately 148,000 horsepower, or 3% (of then available horsepower) of the combined contract operations business of the Partnership and us. The assets sold also included 179 compressor units, comprising approximately 66,000 horsepower, previously leased by us to the Partnership. Total consideration for the transaction was approximately $102.3 million, excluding transaction costs, and consisted of the Partnership’s issuance to us of approximately 4.0 million common units and approximately 80,000 general partner units. Based on the terms of the contribution, conveyance and assumption agreement, the common units and general partner units, including incentive distribution rights, we received in this transaction were not entitled to receive a cash distribution relating to the quarter ended March 31, 2015. As a result, adjustments were made to noncontrolling interest, accumulated other comprehensive income (loss), deferred income taxes and additional paid-in capital to reflect our new ownership percentage in the Partnership.
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In April 2014, the Partnership sold, pursuant to a public underwritten offering, 6,210,000 common units, including 810,000 common units pursuant to an over-allotment option. The Partnership received net proceeds of $169.5 million, after deducting underwriting discounts, commissions and offering expenses, which it used to fund a portion of the April 2014 MidCon Acquisition. In connection with this sale and as permitted under its partnership agreement, the Partnership issued and sold to Archrock General Partner, L.P. (“GP”), our wholly-owned subsidiary and the Partnership’s general partner, in exchange for $3.6 million, approximately 126,000 general partner units to maintain GP’s approximate 2% general partner interest in the Partnership. As a result, adjustments were made to noncontrolling interest, accumulated other comprehensive income (loss), deferred income taxes and additional paid-in capital to reflect our new ownership percentage in the Partnership.
In March 2013, we sold to the Partnership contract operations customer service agreements with 50 customers and a fleet of 363 compressor units used to provide compression services under those agreements, comprising approximately 256,000 horsepower, or 8% (of then available horsepower) of the combined contract operations business of the Partnership and us. The assets sold also included 204 compressor units, comprising approximately 99,000 horsepower, previously leased to the Partnership and contracts relating to approximately 6,000 horsepower of compressor units the Partnership already owned and previously leased to us. Total consideration for the transaction was approximately $174.0 million, excluding transaction costs, and consisted of the Partnership’s issuance to us of approximately 7.1 million common units and approximately 145,000 general partner units. As a result, adjustments were made to noncontrolling interest, accumulated other comprehensive income (loss), deferred income taxes and additional paid-in capital to reflect our new ownership percentage in the Partnership.
The following table presents the effects of changes from net income (loss) attributable to Archrock stockholders and changes in our equity interest of the Partnership on our equity attributable to Archrock stockholders (in thousands):
Years Ended December 31, | |||||||||||
2015 | 2014 | 2013 | |||||||||
Net income (loss) attributable to Archrock stockholders | $ | (105,818 | ) | $ | 98,166 | $ | 123,164 | ||||
Increase in Archrock stockholders’ additional paid in capital for change in ownership of Partnership units | 18,386 | 74,521 | 31,573 | ||||||||
Change from net income (loss) attributable to Archrock stockholders and transfers to/from the noncontrolling interest | $ | (87,432 | ) | $ | 172,687 | $ | 154,737 | ||||
20. Commitments and Contingencies
Rent expense for 2015, 2014 and 2013 was approximately $10.9 million, $9.8 million and $9.9 million, respectively. Commitments for future minimum rental payments with terms in excess of one year at December 31, 2015 are as follows (in thousands):
December 31, 2015 | |||
2016 | $ | 5,591 | |
2017 | 4,876 | ||
2018 | 2,726 | ||
2019 | 1,774 | ||
2020 | 1,456 | ||
Thereafter | 1,881 | ||
Total | $ | 18,304 | |
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We have issued the following guarantees that are not recorded on our accompanying consolidated balance sheet (dollars in thousands):
Term | Maximum Potential Undiscounted Payments as of December 31, 2015 | ||||
Standby letters of credit | 2016 | $ | 9,969 | ||
Performance bonds(1) | 2016 | 1,252 | |||
Maximum potential undiscounted payments | $ | 11,221 | |||
(1) | We have issued guarantees to third parties to ensure performance of our obligations, some of which may be fulfilled by third parties. |
We are subject to a number of taxes that are not income-based. As many of these taxes are subject to audit by the taxing authorities, it is possible that an audit could result in additional taxes due. We accrue for such additional taxes when we determine that it is probable that we have incurred a liability and we can reasonably estimate the amount of the liability. As of December 31, 2015, we had accrued $2.7 million and for the outcomes of non-income based tax audits. We do not expect that the ultimate resolutions of these audits will result in a material variance from the amounts accrued. We do not accrue for unasserted claims for tax audits unless we believe the assertion of a claim is probable, it is probable that it will be determined that the claim is owed and we can reasonably estimate the claim or range of the claim. We also believe the likelihood is remote that the impact of potential unasserted claims from non-income based tax audits could be material to our consolidated financial position, but it is possible that the resolution of future audits could be material to our results of operations or cash flows for the period in which the resolution occurs.
Subject to the provisions of the tax matters agreement between Exterran Corporation and us, both parties agreed to indemnify the primary obligor of any return for tax periods beginning before and ending before or after the Spin-off (including any ongoing or future amendments and audits for these returns) for the portion of the tax liability (including interest and penalties) that relates to their respective operations reported in the filing. As of December 31, 2015, we have recorded a $1.5 million indemnification liability (including penalties and interest) related to non-income based tax audits.
Our business can be hazardous, involving unforeseen circumstances such as uncontrollable flows of natural gas or well fluids and fires or explosions. As is customary in our industry, we review our safety equipment and procedures and carry insurance against some, but not all, risks of our business. Our insurance coverage includes property damage, general liability and commercial automobile liability and other coverage we believe is appropriate. In addition, we have a minimal amount of insurance on our offshore assets. We believe that our insurance coverage is customary for the industry and adequate for our business; however, losses and liabilities not covered by insurance would increase our costs.
Additionally, we are substantially self-insured for workers’ compensation and employee group health claims in view of the relatively high per-incident deductibles we absorb under our insurance arrangements for these risks. Losses up to the deductible amounts are estimated and accrued based upon known facts, historical trends and industry averages.
Indemnifications
On November 3, 2015, we completed the Spin-off of our international contract operations, international aftermarket services and global fabrication businesses. In connection with the Spin-off, we entered into a separation and distribution agreement, which provides for cross-indemnities between Exterran Corporation’s operating subsidiary and us and established procedures for handling claims subject to indemnification and related matters. Generally, the separation and distribution agreement provides for cross-indemnities principally designed to place financial responsibility for the obligations and liabilities of our business with us and financial responsibility for the obligations and liabilities of Exterran Corporation’s business with Exterran Corporation. Pursuant to the agreement, we and Exterran Corporation will generally release the other party from all claims arising prior to the Spin-off that relate to the other party’s business.
F-40
Litigation and Claims
In 2011, the Texas Legislature enacted changes related to the appraisal of natural gas compressors for ad valorem tax purposes by expanding the definitions of “Heavy Equipment Dealer” and “Heavy Equipment” effective from the beginning of 2012 (the “Heavy Equipment Statutes”). Under the revised statutes, we believe we are a Heavy Equipment Dealer, that our natural gas compressors are Heavy Equipment and that we, therefore, are required to file our ad valorem tax renditions under this new methodology. We further believe that, under the Heavy Equipment Statutes, our natural gas compressors are taxable in the counties where we maintain a business location and keep natural gas compressors instead of where the compressors may be located on January 1 of a tax year. A large number of appraisal review boards denied our position, and we filed petitions for review in the appropriate district courts.
As of December 31, 2015, three of these cases have been decided. In each case, the district court held that the revised Heavy Equipment Statutes apply to natural gas compressors. However, in each case, the district court further held that the revised Heavy Equipment Statutes are unconstitutional as applied to natural gas compressors, and that the natural gas compressors of our wholly owned subsidiary Archrock Services Leasing LLC, formerly known as EES Leasing LLC (“EES Leasing”), and Archrock Partners’ subsidiary Archrock Partners Leasing LLC, formerly known as EXLP Leasing LLC (“EXLP Leasing”) are taxable in the counties where they were located on January 1 of the tax year at issue, which is favorable to the county appraisal districts. We appealed all three of these decisions.
On August 25, 2015, the Fourteenth Court of Appeals in Houston, Texas issued a ruling stating that EES Leasing’s and EXLP Leasing’s natural gas compressors are taxable in the counties where they were located on January 1 of the tax year at issue, and it remanded the case to the district court for further evidence on the issue of whether the Heavy Equipment Statutes are constitutional as applied to EES Leasing’s and EXLP Leasing’s compressors. On November 24, 2015, we filed a petition asking the Texas Supreme Court to review this decision. On January 29, 2016, the Texas Supreme Court requested that Galveston Central Appraisal District file a response to our petition for review by February 29, 2016.
On September 23, 2015, the Eighth Court of Appeals in El Paso, Texas decided the other two appellate cases in our favor by affirming the district court’s ruling that the Heavy Equipment Statutes apply to natural gas compressors, and overturning the district court’s ruling that the Heavy Equipment Statutes are unconstitutional as applied to natural gas compressors. The Eighth Court of Appeals also ruled, however, that EES Leasing’s and EXLP Leasing’s natural gas compressors are taxable in the counties where they were located on January 1 of the tax year at issue.
In EES Leasing LLC and EXLP Leasing LLC v. Harris County Appraisal District, the parties filed motions for summary judgment, which are currently pending before the district court. In EES Leasing LLC v. Irion County Appraisal District, the court denied both parties’ respective motions for summary judgment concerning taxes assessed by Irion County for the 2012 tax year, and consolidated the case with EES Leasing’s 2013 tax year case, which also included EXLP Leasing as a party. On August 27, 2015, the Irion County district court abated the consolidated case, EES Leasing LLC and EXLP Leasing LLC v. Irion County Appraisal District, until the final resolution of the appellate cases considering the constitutionality of the Heavy Equipment Statutes, or further order of the court.
As a result of the new methodology, our ad valorem tax expense (which is reflected in our consolidated statements of operations as a component of cost of sales (excluding depreciation and amortization expense)) includes a benefit of $16.0 million during the year ended December 31, 2015. Since the change in methodology became effective in 2012, we have recorded an aggregate benefit of $44.0 million as of December 31, 2015, of which approximately $10.2 million has been agreed to by a number of appraisal review boards and county appraisal districts and $33.8 million has been disputed and is currently in litigation. Recognizing the similarity of the issues and that these cases will ultimately be resolved by the Texas appellate courts, we have reached, or intend to reach, agreements with as many of the appraisal districts as possible to stay or abate any appeals that are pending in district court.
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If our appeals are ultimately unsuccessful, we would be required to pay ad valorem taxes up to the aggregate benefit we have recorded, and the additional ad valorem tax payments may also be subject to substantial penalties and interest. In addition, while we do not expect the ultimate determination of the issue of where the natural gas compressors are taxable under the Heavy Equipment Statutes would have an impact on the amount of taxes due, we could be subject to substantial penalties if we are unsuccessful on this issue. Also, if we are unsuccessful in our litigation with the appraisal districts, or if legislation is enacted in Texas that repeals or alters the Heavy Equipment Statutes such that in the future we do not qualify as a Heavy Equipment Dealer or our compressors do not qualify as Heavy Equipment, then we would likely be required to pay these ad valorem taxes under the old methodology going forward, which would increase our quarterly cost of sales expense up to approximately the amount of our then most recent quarterly benefit recorded. If this litigation is resolved against us in whole or in part, or if in the future we do not qualify as a Heavy Equipment Dealer or our compressors do not qualify as Heavy Equipment because of new or revised Texas statutes, we will incur additional taxes and could be subject to substantial penalties and interest, which would impact our future results of operations, financial condition and cash flows and also our ability to pay dividends in the future.
In the ordinary course of business, we are also involved in various other pending or threatened legal actions. While management is unable to predict the ultimate outcome of these actions, it believes that any ultimate liability arising from any of these other actions will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. However, because of the inherent uncertainty of litigation and arbitration proceedings, we cannot provide assurance that the resolution of any particular claim or proceeding to which we are a party will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.
21. Recent Accounting Developments
In February 2016, the Financial Accounting Standards Board (“FASB”) issued an update which establishes a right-of-use model that requires a lessee to record a right-of-use asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. Under the new guidance, lessor accounting is largely unchanged. The new standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. We are currently evaluating the impact of this update on our financial statements.
In November 2015, the FASB issued an update related to the balance sheet classification of deferred taxes. The update simplifies the presentation of deferred income taxes to require that all deferred income tax assets and liabilities be classified as noncurrent and eliminates the current classification. Proration of valuation allowances is eliminated and classification of a deferred tax asset or liability is no longer based on the classification of the related asset or liability. The update will be effective for reporting periods beginning after December 15, 2016 and can be applied prospectively or retrospectively. Early adoption is allowed and we early adopted this update, retrospectively, which resulted in a reclassification of $5.1 million from current deferred tax assets in 2014 to noncurrent deferred tax liabilities.
In July 2015, the FASB issued an update which will require an entity to measure inventory at the lower of cost and net realizable value. Net realizable value is defined as the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. For public business entities, this update is effective on a prospective basis for interim and annual periods beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the impact of this update on our financial statements.
In April 2015, the FASB issued an update that addresses the presentation of debt issuance costs. The update requires an entity to present such costs in the balance sheet as a direct deduction from the carrying amount of the related debt liability rather than as an asset. Amortization of the costs will continue to be reported as interest expense. In August 2015, the FASB issued a subsequent update which clarifies that the guidance in the previous update does not apply to line-of-credit arrangements. Per the subsequent update, line-of-credit arrangements will continue to defer and present debt issuance costs as an asset and subsequently amortize the deferred debt costs ratably over the term of the arrangement. Upon transition, an entity is required to comply with the applicable disclosures for a change in an accounting principle. The update will be effective for reporting periods beginning after December 15, 2015 on a retrospective basis. Early adoption is permitted. Other than the revised balance sheet presentation of debt issuance costs from an asset to a deduction from the carrying amount of the debt liability and related disclosures, the adoption of this update is not expected to have an impact on our financial statements.
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In February 2015, the FASB issued an update which revises the consolidation model. The update modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (“VIEs”) or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership and affects the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships. The update will be effective for reporting periods beginning after December 15, 2015. Early adoption is permitted. We do not believe the adoption of this update will have a material impact on our financial statements.
In May 2014, the FASB issued an update related to revenue recognition. The update outlines a single comprehensive model for companies to use in accounting for revenue arising from contracts with customers and supersedes the most current revenue recognition guidance, including industry-specific guidance. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The update also requires disclosures enabling users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The update will be effective for reporting periods beginning after December 15, 2017, including interim periods within the reporting period. Early adoption is permitted for reporting periods beginning after December 15, 2016. Companies may use either a full retrospective or a modified retrospective approach to adopt this update. We are currently evaluating the potential impact of the update on our financial statements.
22. Reportable Segments and Geographic Information
We manage our business segments primarily based upon the type of product or service provided. We have two reportable segments which we operate within the U.S.: contract operations and aftermarket services. The contract operations segment primarily provides natural gas compression services to meet specific customer requirements. The aftermarket services segment provides a full range of services to support the compression needs of customers, from parts sales and normal maintenance services to full operation of a customer’s owned assets.
We evaluate the performance of our segments based on gross margin for each segment. Revenue includes only sales to external customers. We do not include intersegment sales when we evaluate our segments’ performance.
During each of the years ended December 31, 2015 and 2014, Williams Partners, L.P. accounted for approximately 12% and 10%, respectively, of our consolidated revenue. No other customer accounted for more than 10% of our consolidated revenue during the years ended December 31, 2015 and 2014 and no single customer accounted for more than 10% of our consolidated revenue during the year ended December 31, 2013.
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The following table presents sales and other financial information by reportable segment during the years ended December 31, 2015, 2014 and 2013 (in thousands):
Contract Operations | Aftermarket Services | Reportable Segments Total | Other (1) | Total (2) | |||||||||||||||
2015: | |||||||||||||||||||
Revenue from external customers | $ | 781,166 | $ | 216,942 | $ | 998,108 | $ | — | $ | 998,108 | |||||||||
Gross margin (3) | 461,765 | 41,297 | 503,062 | — | 503,062 | ||||||||||||||
Total assets | 2,248,191 | 149,008 | 2,397,199 | 287,944 | 2,685,143 | ||||||||||||||
Capital expenditures | 227,248 | 2,296 | 229,544 | 26,598 | 256,142 | ||||||||||||||
2014: | |||||||||||||||||||
Revenue from external customers | $ | 729,103 | $ | 230,050 | $ | 959,153 | $ | — | $ | 959,153 | |||||||||
Gross margin (3) | 412,961 | 41,799 | 454,760 | — | 454,760 | ||||||||||||||
Total assets | 2,446,633 | 62,485 | 2,509,118 | 334,516 | 2,843,634 | ||||||||||||||
Capital expenditures | 371,734 | 825 | 372,559 | 11,282 | 383,841 | ||||||||||||||
2013: | |||||||||||||||||||
Revenue from external customers | $ | 627,844 | $ | 234,928 | $ | 862,772 | $ | — | $ | 862,772 | |||||||||
Gross margin (3) | 345,355 | 46,439 | 391,794 | — | 391,794 | ||||||||||||||
Total assets | 1,907,097 | 67,693 | 1,974,790 | 238,220 | 2,213,010 | ||||||||||||||
Capital expenditures | 275,408 | 935 | 276,343 | 15,187 | 291,530 | ||||||||||||||
(1) | Includes corporate related items. |
(2) | Totals exclude assets, capital expenditures and the operating results of discontinued operations. |
(3) | Gross margin, a non-GAAP financial measure, is reconciled, in total, to net income (loss), its most directly comparable measure calculated and presented in accordance with U.S. GAAP, below. |
The following table presents assets from reportable segments to total assets as of December 31, 2015 and 2014 (in thousands):
December 31, | |||||||
2015 | 2014 | ||||||
Assets from reportable segments | $ | 2,397,199 | $ | 2,509,118 | |||
Other assets (1) | 287,944 | 334,516 | |||||
Assets associated with discontinued operations | 21,620 | 2,083,205 | |||||
Consolidated assets | $ | 2,706,763 | $ | 4,926,839 | |||
(1) | Includes corporate related items. |
We define gross margin as total revenue less cost of sales (excluding depreciation and amortization expense). Gross margin is included as a supplemental disclosure because it is a primary measure used by our management to evaluate the results of revenue and cost of sales (excluding depreciation and amortization expense), which are key components of our operations. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.
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The following table reconciles net income (loss) to gross margin (in thousands):
Years Ended December 31, | |||||||||||
2015 | 2014 | 2013 | |||||||||
Net income (loss) | $ | (98,966 | ) | $ | 125,882 | $ | 155,742 | ||||
Selling, general and administrative | 131,919 | 132,651 | 118,851 | ||||||||
Depreciation and amortization | 229,127 | 212,268 | 187,476 | ||||||||
Long-lived asset impairment | 124,979 | 42,828 | 16,696 | ||||||||
Restructuring charges | 4,745 | 5,394 | — | ||||||||
Goodwill impairment | 3,738 | — | — | ||||||||
Interest expense | 107,617 | 112,273 | 112,194 | ||||||||
Debt extinguishment costs | 9,201 | — | — | ||||||||
Other (income) expense, net | (2,079 | ) | (5,475 | ) | (22,535 | ) | |||||
Provision for (benefit from) income taxes | 53,189 | (28,066 | ) | (17,840 | ) | ||||||
Income from discontinued operations, net of tax | (60,408 | ) | (142,995 | ) | (158,790 | ) | |||||
Gross margin | $ | 503,062 | $ | 454,760 | $ | 391,794 | |||||
23. Selected Quarterly Financial Data (Unaudited)
In management’s opinion, the summarized quarterly financial data below (in thousands, except per share amounts) contains all appropriate adjustments, all of which are normally recurring adjustments, considered necessary to present fairly our consolidated financial position and results of operations for the respective periods.
March 31, 2015(1) | June 30, 2015(2) | September 30, 2015(3) | December 31, 2015(4) | ||||||||||||
Revenue from external customers | $ | 252,873 | $ | 255,062 | $ | 248,863 | $ | 241,310 | |||||||
Gross profit(9) | 70,797 | 67,643 | 52,949 | (21,541 | ) | ||||||||||
Net income (loss) attributable to Archrock stockholders | 32,142 | (1,389 | ) | (6,304 | ) | (130,267 | ) | ||||||||
Net income (loss) attributable to Archrock common stockholders per share: | |||||||||||||||
Basic | $ | 0.47 | $ | (0.02 | ) | $ | (0.09 | ) | $ | (1.91 | ) | ||||
Diluted | 0.47 | (0.02 | ) | (0.09 | ) | (1.91 | ) | ||||||||
March 31, 2014(5) | June 30, 2014(6) | September 30, 2014(7) | December 31, 2014(8) | ||||||||||||
Revenue from external customers | $ | 209,738 | $ | 239,153 | $ | 247,453 | $ | 262,809 | |||||||
Gross profit(9) | 46,396 | 56,616 | 59,738 | 58,065 | |||||||||||
Net income attributable to Archrock stockholders | 32,596 | 12,377 | 34,050 | 19,143 | |||||||||||
Net income attributable to Archrock common stockholders per share: | |||||||||||||||
Basic | $ | 0.50 | $ | 0.19 | $ | 0.50 | $ | 0.28 | |||||||
Diluted | 0.50 | 0.19 | 0.48 | 0.28 | |||||||||||
(1) | In the first quarter of 2015, we recorded $34.9 million of income from discontinued operations, net of tax (see Note 2 (“Discontinued Operations”)) and $8.2 million of long-lived asset impairments (see Note 12 (“Long-Lived Asset Impairment”)). |
(2) | In the second quarter of 2015, we completed the April 2015 Contract Operations Acquisition (see Note 3 (“Business Acquisitions”)). Additionally, we recorded $3.5 million of income from discontinued operations, net of tax (see Note 2 (“Discontinued Operations”)), $9.5 million of long-lived asset impairments (see Note 12 (“Long-Lived Asset Impairment”) and $1.2 million of restructuring charges (see Note 13 (“Restructuring Charges”)). |
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(3) | In the third quarter of 2015 we recorded $13.7 million of income from discontinued operations, net of tax (see Note 2 (“Discontinued Operations”)), $19.9 million of long-lived asset impairments (see Note 12 (“Long-Lived Asset Impairment”)) and $0.3 million of restructuring charges (see Note 13 (“Restructuring Charges”)). |
(4) | In the fourth quarter of 2015, we recorded $8.3 million of income from discontinued operations, net of tax (see Note 2 (“Discontinued Operations”)), $3.7 million of goodwill impairment (see Note 6 (“Goodwill”)), $87.4 million of long-lived asset impairments (see Note 12 (“Long-Lived Asset Impairment”)) and $3.2 million of restructuring charges (see Note 13 (“Restructuring Charges”)). |
(5) | In the first quarter of 2014, we recorded $41.4 million of income from discontinued operations, net of tax (see Note 2 (“Discontinued Operations”)), $3.8 million of long-lived asset impairments (see Note 12 (“Long-Lived Asset Impairment”)) and $4.8 million of restructuring charges (see Note 13 “Restructuring Charges”)). |
(6) | In the second quarter of 2014 , we recorded $24.0 million of income from discontinued operations, net of tax (see Note 2 (“Discontinued Operations”)), $9.8 million of long-lived asset impairments (see Note 12 (“Long-Lived Asset Impairment”)) and $0.4 million of restructuring charges (see Note 13 “Restructuring Charges”)). |
(7) | In the third quarter of 2014, we recorded $32.6 million of income from discontinued operations, net of tax (see Note 2 (“Discontinued Operations”)), $11.3 million of long-lived asset impairments (see Note 12 (“Long-Lived Asset Impairment”)) and $0.2 million of restructuring charges (see Note 13 (“Restructuring Charges”)). |
(8) | In the fourth quarter of 2014, we recorded $45.0 million of income from discontinued operations, net of tax (see Note 2 (“Discontinued Operations”)) and $17.9 million of long-lived asset impairments (see Note 12 (“Long-Lived Asset Impairment”)). |
(9) | Gross profit is defined as revenue less cost of sales, direct depreciation and amortization expense and long-lived asset impairment charges. |
24. Subsequent Event
In January 2016, Exterran Corporation received an additional installment payment, including an annual charge, of $5.2 million from PDVSA Gas relating to the 2012 sale of its Venezuelan joint ventures’ previously nationalized assets. Pursuant to the separation and distribution agreement, Exterran Corporation transferred cash to us based on the notional amount of the payment they received from PDVSA Gas in January 2016. The transfer of cash to us will be recognized as an increase to stockholders’ equity on our consolidated balance sheet in the first quarter of 2016.
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ARCHROCK, INC.
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
(In thousands)
Description | Balance at Beginning of Period | Charged to Costs and Expenses | Deductions | Balance at End of Period | |||||||||
Allowance for doubtful accounts deducted from accounts receivable in the balance sheet | |||||||||||||
December 31, 2015 | $ | 2,286 | 3,075 | 2,018 | (1) | $ | 3,343 | ||||||
December 31, 2014 | 1,224 | 1,743 | 681 | (1) | 2,286 | ||||||||
December 31, 2013 | 2,938 | (191 | ) | 1,523 | (1) | 1,224 | |||||||
Allowance for obsolete and slow moving inventory deducted from inventories in the balance sheet | |||||||||||||
December 31, 2015 | $ | 11,500 | 4,286 | 5,976 | (2) | $ | 9,810 | ||||||
December 31, 2014 | 5,871 | 8,896 | 3,267 | (2) | 11,500 | ||||||||
December 31, 2013 | 4,107 | 3,904 | 2,140 | (2) | 5,871 | ||||||||
Allowance for deferred tax assets not expected to be realized | |||||||||||||
December 31, 2015 | 633 | — | — | 633 | |||||||||
December 31, 2014 | 633 | — | — | 633 | |||||||||
December 31, 2013 | 633 | — | — | 633 | |||||||||
(1) | Uncollectible accounts written off. |
(2) | Obsolete inventory written off at cost of value received. |
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