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:

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.

Competitive Strengths

We believe we have the following key competitive strengths:

Business Strategies

We intend to continue to capitalize on our competitive strengths to meet our customers’ needs through the following key strategies:

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.

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.”

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:

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.”

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:

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.

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.

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:

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.

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.

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:

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.

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.

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.

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.

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.

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.

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: