0001389050-20-000028.txt : 20200221 0001389050-20-000028.hdr.sgml : 20200221 20200221124851 ACCESSION NUMBER: 0001389050-20-000028 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 164 CONFORMED PERIOD OF REPORT: 20191231 FILED AS OF DATE: 20200221 DATE AS OF CHANGE: 20200221 FILER: COMPANY DATA: COMPANY CONFORMED NAME: Archrock, Inc. CENTRAL INDEX KEY: 0001389050 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS TRANSMISSION [4922] IRS NUMBER: 743204509 FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-33666 FILM NUMBER: 20638412 BUSINESS ADDRESS: STREET 1: 9807 KATY FREEWAY STREET 2: STE 100 CITY: HOUSTON STATE: TX ZIP: 77024 BUSINESS PHONE: 281-836-8000 MAIL ADDRESS: STREET 1: 9807 KATY FREEWAY STREET 2: STE 100 CITY: HOUSTON STATE: TX ZIP: 77024 FORMER COMPANY: FORMER CONFORMED NAME: EXTERRAN HOLDINGS INC. DATE OF NAME CHANGE: 20070619 FORMER COMPANY: FORMER CONFORMED NAME: Iliad Holdings, INC DATE OF NAME CHANGE: 20070206 10-K 1 a201910karoc.htm 10-K Document
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549 
Form 10-K  

(MARK ONE) 
      ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
For the fiscal year ended December 31, 2019
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.)
9807 Katy Freeway, Suite 100, Houston, Texas 77024
(Address of principal executive offices, zip code)
(281836-8000
(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Trading Symbol
 
Name of exchange on which registered
Common Stock, $0.01 par value per share
 
AROC
 
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   
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes   No 
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes   No 
 
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files).  Yes   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.  
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
 
Accelerated filer 
Non-accelerated filer
 
Smaller reporting company
 

 
Emerging growth company
 
 
 
 
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes   No 
Aggregate market value of the common stock of the registrant held by non-affiliates as of June 30, 2019: $1,357,045,157.
Number of shares of the common stock of the registrant outstanding as of February 13, 2020: 152,879,266 shares.

______________________________________________________
DOCUMENTS INCORPORATED BY REFERENCE 
Portions of the registrant’s definitive proxy statement for the 2019 Meeting of Stockholders, which is expected to be filed with the Securities and Exchange Commission within 120 days after December 31, 2019, are incorporated by reference into Part III of this Form 10-K.
 



TABLE OF CONTENTS
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


2


GLOSSARY

The following terms and abbreviations appearing in the text of this report have the meanings indicated below.

2006 Partnership LTIP
Archrock Partners, L.P. Long Term Incentive Plan, adopted in October 2006
2007 Plan
Archrock, Inc. 2007 Stock Incentive Plan
2013 Plan
Archrock, Inc. 2013 Stock Incentive Plan
2017 Partnership LTIP
Archrock Partners, L.P. Long Term Incentive Plan, adopted in April 2017
2019 Form 10-K
Archrock, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2019
2021 Notes
$350.0 million of 6% senior notes due April 2021, issued in March 2013
2022 Notes
$350.0 million of 6% senior notes due October 2022, issued in April 2014
2027 Notes
$500.0 million of 6.875% senior notes due April 2027, issued in March 2019
2028 Notes
$500.0 million of 6.25% senior notes due April 2028, issued in December 2019
Amendment No. 1
Amendment No. 1 to Credit Agreement, dated February 23, 2018, which amended that Credit Agreement, dated as of March 30, 2017, which governs the Credit Facility
Amendment No. 2
Amendment No. 2 to Credit Agreement, dated November 8, 2019, which amended that Credit Agreement, dated as of March 30, 2017, which governs the Credit Facility
AMNAX
Alerian Midstream Energy Index
Anadarko
Anadarko Petroleum Company
Archrock, our, we, us
Archrock, Inc., individually and together with its wholly-owned subsidiaries
Archrock Credit Facility
Archrock’s $350 million revolving credit facility terminated in April 2018 in connection with the Merger and Amendment No.1
ASC 606 Revenue
Accounting Standards Codification Topic 606 Revenue from Contracts with Customers
ASC 840 Leases
Accounting Standards Codification Topic 840 Leases
ASC 842 Leases
Accounting Standards Codification Topic 842 Leases
ASU 2016-09
Accounting Standards Update No. 2016-09—Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting
ASU 2016-13
Accounting Standards Update No. 2016-13—Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments
ASU 2017-04
Accounting Standards Update No. 2017-04—Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment
ASU 2017-12
Accounting Standards Update No. 2017-12—Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities
ASU 2018-02
Accounting Standards Update No. 2018-02—Income Statement—Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income
ASU 2018-13
Accounting Standards Update No. 2018-13—Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement
ASU 2019-12
Accounting Standards Update No. 2019-12—Income Taxes (Topic 740)—Simplifying the Accounting for Income Taxes
BBA
British Bankers’ Association
Bcf/d
Billion cubic feet per day
BLM
U.S. Department of the Interior’s Bureau of Land Management
CAA
Clean Air Act
CERCLA
Comprehensive Environmental Response, Compensation, and Liability Act
Code
Internal Revenue Code of 1986, as amended
Credit Facility
$1.25 billion asset-based revolving credit facility, as amended by Amendment No. 2
CWA
Clean Water Act
EBITDA
Earnings before interest, taxes, depreciation and amortization
EIA
U.S. Energy Information Administration

3


Elite Acquisition
Transaction completed on August 1, 2019 pursuant to the Asset Purchase Agreement entered into with Elite Compression on June 23, 2019
Elite Compression
Elite Compression Services, LLC
EPA
U.S. Environmental Protection Agency
ERP
Enterprise Resource Planning
ESPP
2017 Archrock, Inc. Employee Stock Purchase Plan
Exchange Act
Securities Exchange Act of 1934, as amended
FASB
Financial Accounting Standards Board
Financial Statements
Consolidated financial statements included in Part IV, Item 15 of this 2019 Form 10-K
Former Credit Facility
Partnership’s $825.0 million revolving credit facility and $150.0 million term loan, terminated in March 2017
GAAP
U.S. generally accepted accounting principles
General Partner
Archrock General Partner, L.P., a wholly owned subsidiary of Archrock and the Partnership’s general partner
Harvest
Harvest Four Corners, LLC
Harvest Sale
Transaction completed on August 1, 2019 pursuant to the Asset Purchase Agreement entered into with Harvest on June 23, 2019
Hilcorp
Hilcorp Energy Company
IRS
Internal Revenue Service
JDH Capital
JDH Capital Holdings, L.P.
LIBOR
London Interbank Offered Rate
Merger
Transaction completed on April 26, 2018 in which Archrock acquired all of the Partnership’s outstanding common units not already owned by Archrock pursuant to the Agreement and Plan of Merger, dated as of January 1, 2018, among Archrock and the Partnership, which was amended by Amendment No. 1 to Agreement and Plan of Merger on January 11, 2018
MMb/d
Million barrels per day
NAAQS
National Ambient Air Quality Standards
NOL
Net operating loss
NSPS
New Source Performance Standards
OSHA
Occupational Safety and Health Act
OTC
Over-the-counter, as related to aftermarket services parts and components
Paris Agreement
Resulting agreement of the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change held in Paris, France
Partnership
Archrock Partners, L.P., together with its subsidiaries
Partnership Debt Agreements
Partnership Credit Facility, 2022 Notes, 2027 Notes and 2028 Notes, collectively
ppb
Parts per billion
RCRA
Resource Conservation and Recovery Act
ROU
Right-of-use, as related to the lease model under ASC Topic 842 Leases
S&P 500
S&P 500 Composite Stock Price Index
SEC
U.S. Securities and Exchange Commission
SG&A
Selling, general and administrative
Spin-off
Spin-off completed in November 2015 of our international contract operations, international aftermarket services and global fabrication businesses into a standalone public company operating as Exterran Corporation
Tax Cuts and Jobs Act, TCJA
Public Law No. 115-97, a comprehensive tax reform bill signed into law on December 22, 2017
TCEQ
Texas Commission on Environmental Quality
U.S.
United States of America
VOC
Volatile organic compounds
Williams Partners
Williams Partners, L.P.

4



FORWARD-LOOKING STATEMENTS
 
This 2019 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 2019 Form 10-K are forward-looking statements within the meaning of Section 21E of 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 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 2019 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 materially from those in these forward-looking statements are described 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 2019 Form 10-K.

All forward-looking statements included in this 2019 Form 10-K are based on information available to us on the date of this 2019 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 2019 Form 10-K.


5


PART I
 
Item 1. Business

We were incorporated in February 2007 as a wholly-owned subsidiary of Universal Compression Holdings, Inc. In August 2007, Universal Compression Holdings, Inc. and Hanover Compressor Company merged into our wholly-owned subsidiaries and we became the parent entity of Universal Compression Holdings, Inc. and Hanover Compressor Company, named “Exterran Holdings, Inc.” In November 2015, we completed the Spin-off of our international contract operations, international aftermarket services and global fabrication business into a standalone public company operating as Exterran Corporation, and we were renamed “Archrock, Inc.”

We are an energy infrastructure company with a pure-play focus on midstream natural gas compression. We are 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 business supports a must-run service that is essential to the production, processing, transportation and storage of natural gas. Our geographic diversity, technically experienced personnel and large fleet of natural gas compression equipment enable us to provide reliable contract operations services to our customers.

We operate in two business segments:

Contract Operations. Our contract operations business is comprised of 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 our customers that own compression equipment, including operations, maintenance, overhaul and reconfiguration services and sales of parts and components.

Recent Business Developments

2028 Notes Offering

On December 20, 2019, we completed a private offering of $500.0 million aggregate principal amount of 6.25% senior notes due April 2028. We received net proceeds of $491.8 million after issuance costs, which were used to repay borrowings outstanding under our Credit Facility. See Note 13 (“Long-Term Debt”) to our Financial Statements for further details of this transaction.

Amendment to the Credit Facility

On November 8, 2019, we entered into Amendment No. 2, which extended the maturity date of, and changed the applicable margins for borrowings under, our Credit Facility. See Part II Item 7 “Liquidity and Capital Resources — Financial Resources” and Note 13 (“Long-Term Debt”) to our Financial Statements for further details of this amendment.

Elite Acquisition

On August 1, 2019, we completed the Elite Acquisition whereby we acquired from Elite Compression substantially all of its assets, including a fleet of predominantly large compressors comprising approximately 430,000 horsepower, vehicles, real property and inventory, and certain liabilities for aggregate consideration consisting of $214.0 million in cash and 21.7 million shares of common stock with an acquisition date fair value of $225.9 million. The cash portion of the acquisition was funded with borrowings on the Credit Facility.

Harvest Sale

On August 1, 2019, we completed an asset sale in which Harvest acquired from us approximately 80,000 active and idle compression horsepower, vehicles and parts inventory for cash consideration of $30.0 million. We recorded a $6.6 million gain on the sale of these assets in the third quarter of 2019.

See Note 4 (“Business Transactions”) to our Financial Statements for further details of the Elite Acquisition and the Harvest Sale.


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2027 Notes Offering and 2021 Notes Extinguishment

On March 21, 2019, we completed a private offering of $500.0 million aggregate principal amount of 6.875% senior notes due April 2027. We received net proceeds of $491.2 million after issuance costs, which were used to repay borrowings outstanding under our Credit Facility.

On April 5, 2019, we repaid the 2021 Notes with borrowings from our Credit Facility.

See Note 13 (“Long-Term Debt”) to our Financial Statements for further details of these transactions.

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 location and each customer’s unique needs, these services include designing, sourcing, owning, installing, operating, servicing, repairing and maintaining the equipment. We repackage or reconfigure our existing fleet to adapt to our customers’ compression needs and work closely with our customers’ field service personnel so that the compression services can be adjusted to efficiently match changing characteristics of the reservoir and the natural gas produced. We primarily utilize reciprocating compressors driven by natural gas-powered engines.

Our equipment is maintained in accordance with our established maintenance schedules, standards and procedures. These maintenance practices are updated as technology changes and as our operations group develops new techniques and procedures to better service our equipment. 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 practices maximize equipment life and unit availability, minimize avoidable downtime and lower the overall maintenance expenditures over the equipment life. On average, our compression packages undergo a major overhaul once every seven years depending on the type, size and utilization of the compressor.

We generate revenue for our services pursuant to fee-based agreements with our customers, which limit our direct exposure to commodity price fluctuations. 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 generally ranges from 12 to 60 months, contract operations services generally continue on a month-to-month basis 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, which enhances the stability and predictability of our cash flows. Additionally, the natural gas we use as fuel for our compression packages is supplied by our customers, which further limits our exposure to commodity price fluctuations. See “General Terms of our Contract Operations Customer Service Agreements” below for further details on our service agreements.

We maintain field service locations from which we can service and overhaul our compression 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 below. As of December 31, 2019, our contract operations segment provided contract operations services using a fleet of 6,430 natural gas compressors with an aggregate capacity of 4.4 million horsepower. During the years ended December 31, 2019, 2018 and 2017, we generated 80%, 74% and 77%, respectively, of our total revenue and 93%, 91% and 93%, respectively, of our total gross margin 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 7 “Non-GAAP Financial Measures.”

Compression Fleet

The following table summarizes the size of our natural gas compression fleet as of December 31, 2019:

 
 
Number
of Units
 
Aggregate
Horsepower
(in thousands)
 
% of
Horsepower
0 — 1,000 horsepower per unit
 
4,299

 
1,155

 
26
%
1,001 — 1,500 horsepower per unit
 
1,549

 
2,083

 
48
%
Over 1,500 horsepower per unit
 
582

 
1,157

 
26
%
Total
 
6,430

 
4,395

 
100
%

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We continue efforts to standardize our compression fleet around major components and key suppliers. The standardization of our fleet:

enables us to minimize our fleet operating costs and maintenance capital requirements;

reduces 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 higher uptime while maintaining lower operating costs.

Aftermarket Services Overview

Our aftermarket services business sells parts and components and provides operations, maintenance, overhaul and reconfiguration services to customers who own compression 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. In addition, our aftermarket services business provides opportunities to cross-sell our contract operations services. During the years ended December 31, 2019, 2018 and 2017, we generated 20%, 26% and 23%, respectively, of our total revenue and 7%, 9% and 7%, respectively, of our total gross margin from aftermarket services.

Competitive Strengths

We believe we have the following key competitive strengths:

Large horsepower. We have the largest fleet of large horsepower equipment among all outsourced compression service providers in the U.S. As of December 31, 2019, 74% of our fleet, as measured by operating horsepower, was comprised of units that exceed 1,000 horsepower per unit. We believe the trends driving demand for large horsepower units will continue. These trends include (i) high levels of associated gas production from shale wells, which is generally produced at a lower initial pressure than dry gas wells, (ii) pad drilling, which brings multiple wells to a single well site with larger volumes of gas, (iii) increasing well lateral lengths, which increase natural gas flow through gas gathering systems and (iv) high probability drilling programs that allow for efficient infrastructure planning.

Superior customer service. 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 uptime and our customers’ production levels. Our sales efforts concentrate on demonstrating our commitment to enhancing our customers’ cash flows through superior customer service and after-market support.

Large and stable customer base. We have strong relationships with a deep base of oil and gas producers and midstream companies. Our contract operations revenue base is sourced from approximately 600 customers operating throughout all major U.S. oil and natural gas producing regions.

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 any given month. Our compression packages, on average, operate at a customer location for approximately three years. We believe this fee structure and the longevity of our operations reduces volatility and enhances the stability and predictability of our cash flows.

Large fleet in substantially all major U.S. 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, mean 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.


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Long operating history. We have a long, sustained history of operating in the compression industry that provides an advantage compared to our younger competitors. We have extensive experience working with our customers to meet their evolving needs, a deep database of fleet financial and operating metrics and a proven ability to safely manage our business in a variety of commodity and economic environments.

Financial resilience and flexibility. We have historically shown and are committed to maintaining capital discipline and financial strength, which is critical in a cyclical business such as ours. Maintaining ample liquidity and a prudent balance sheet supports our ability to continue to deliver on our long-term strategies and positions us to take advantage of future growth opportunities as they arise.

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 compression 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 oil and natural gas production, decreasing natural reservoir pressures and expected increased natural gas demand in the U.S. from the growth of liquified natural gas exports, exports of natural gas via pipeline to Mexico, power generation and industrial uses.

Improve profitability. We are focused on increasing productivity and optimizing our processes. In the fourth quarter of 2018 we began a process and technology transformation project that will, among other things, upgrade or replace our existing ERP, supply chain and inventory management systems and expand the remote monitoring capabilities of our compression fleet. By using technology to make our systems and processes more efficient, we intend to lower our internal costs and improve our profitability over time. Additionally, strong continued demand for our services should allow us to maintain utilization and pricing.

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 primary business segment and represented 93% of our gross margin during 2019. 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. 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 7% of our gross margin during 2019, to provide services and parts to support the operation of this equipment.

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. Our service offerings focus primarily on the following cycle stages:

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. These applications utilize low- to mid-range horsepower compression equipment located at or near the wellhead or large horsepower compression equipment of 1,000 horsepower and higher for a centralized gas lift system servicing multiple wells. 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.


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Processing Applications — Compressors may also be used in combination with natural gas production and processing equipment to process natural gas into other marketable energy sources. In addition, compression services are used for compression applications in refineries and petrochemical plants. Processing applications typically utilize multiple large horsepower compressors.

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 large horsepower compression equipment of 1,000 horsepower and higher.

Many oil and 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 compression packages 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 oil and 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 liquified natural gas exports and exports of natural gas via pipeline to Mexico.

Oil and Natural Gas Industry Cyclicality and Volatility

Demand for our products and services is correlated to natural gas production. Fluctuations in energy prices can affect the levels of expenditures by our customers, production volumes and ultimately, demand for our products and services; however, we believe our contract operations business is typically less impacted by commodity prices for the following reasons:

fee-based contracts minimize our direct commodity price exposure;

the natural gas we use as fuel for our compression packages is supplied by our customers, further reducing our direct exposure to commodity price risk;

compression services are a necessary part of midstream energy infrastructure that facilitate the transportation of natural gas through gathering systems;

our contract operations business is tied primarily to oil and natural gas production, transportation and consumption, which are generally less cyclical in nature than exploration and new well drilling and completion activities;

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

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our compression packages operate at a customer location for an average of approximately three years during which time our customers are generally required to pay a fixed monthly fee regardless of the volume of natural gas we compress in any given month.

Seasonal Fluctuations

Our results of operations have not historically reflected any material seasonal tendencies and we do not believe that seasonal fluctuations will have a material impact on us in the foreseeable future.

Market, Suppliers and Customers

We conduct our contract operations activities in substantially all major oil and natural gas producing areas throughout the U.S. and have supply agreements with multiple suppliers to meet our compression equipment needs.

Our customer base consists primarily of companies engaged in all aspects of the oil and natural gas industry including large integrated and independent oil and natural gas producers, processors, gatherers and transporters.

We have entered into preferred vendor arrangements with some of our customers that give us preferential consideration for their compression needs. In exchange, we provide these customers with enhanced product availability, product support and favorable pricing.

During the years ended December 31, 2019, 2018 and 2017, Williams Partners accounted for 8%, 11% and 13%, respectively, of our contract operations and aftermarket services revenue. No other customer accounted for 10% or more of our revenue during these years.

Sales and Marketing

Our marketing and client service functions are coordinated and performed by our sales and field service personnel. Sales and field service personnel regularly visit our customers to ensure customer satisfaction, determine customer needs as to services currently being provided and ascertain potential future compression services requirements. This ongoing communication allows us to respond swiftly to customer requests.

General Terms of our Contract Operations Customer 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. The following describes select material terms common to our standard contract operations service agreements.

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 generally ranges from 12 to 60 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 except for 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 services and support and use our compression equipment to provide the contract operations services 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 and Risk of Loss. We own and retain title to or have an exclusive possessory interest in all compression equipment used to provide contract operations services and we generally bear risk of loss for such equipment to the extent the loss is 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, workers’ compensation, employer’s liability, automobile and excess liability insurance. Our insurance coverage includes property damage, general liability and commercial automobile liability and other coverage we believe is appropriate. 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. We are also self-insured for property damage to our offshore assets.

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 technological changes within our industry and changes in economic conditions as a whole, more readily take advantage of acquisitions and other 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 and quality and reliability of our compression packages and related services.

Increased size and geographic density offer compression services providers operating and cost advantages. As the number of compression locations 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 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

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 trend in environmental regulation has been 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 CAA and regulations thereunder, which regulate air emissions; the CWA and regulations thereunder, which regulate the discharge of pollutants in industrial wastewater and storm water runoff; the RCRA and regulations thereunder, which regulate the management and disposal of hazardous and non-hazardous solid wastes; and the CERCLA and regulations thereunder, known more commonly as “Superfund,” which impose liability for the remediation of releases of hazardous substances in the environment. We are also subject to regulation under the 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.

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New Source Performance Standards

On June 3, 2016, the EPA issued final regulations amending the NSPS for the oil and natural gas source category and applying to sources of emissions of methane and VOC from certain processes, activities and equipment that is constructed, modified or reconstructed after September 18, 2015. Specifically, the regulation contains both methane and VOC standards for several emission sources not previously 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 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. In June 2017, the EPA proposed and took public comment on a two-year stay of the fugitive emissions requirements, well site pneumatic standards and closed vent certification. The EPA sought additional comment in November 2017 in support of the proposed rule, but has not finalized the two-year stay. In October 2018 and August 2019, the EPA proposed deregulatory amendments to the 2016 rule intended to streamline implementation, reduce duplicative EPA and state requirements and decrease the burden of compliance. The EPA has not yet issued a final rule based on either proposal. At this time, we do not believe that if finalized these rules will have a material adverse impact on our business, financial condition, results of operations or cash flows.

Venting and Flaring on Federal Lands

On November 18, 2016, the BLM published final rules to reduce venting and flaring on federal and tribal lands. The rules set forth some novel requirements regarding leak detection inspections at compressor stations and imposed requirements to reduce emissions from pneumatic controllers and pumps, among other things. In December 2017, the BLM finalized suspension of certain requirements of the November 2016 final rule until January 2019. In September 2018, the BLM finalized a rule rescinding the novel requirements pertaining to waste-minimization plans, gas-capture percentages, well drilling, well completion and related operations, pneumatic controllers, pneumatic diaphragm pumps, storage vessels and leak detection and repair. The BLM also revised other provisions related to venting and flaring. California, New Mexico and various environmental groups filed a lawsuit challenging the September 2018 final rule, which is still pending.

National Ambient Air Quality Standards

On October 1, 2015, the EPA issued a new NAAQS ozone standard of 70 ppb, which is a reduction from the 75 ppb standard set in 2008. This new standard became effective on December 28, 2015, and the EPA completed designating attainment/non-attainment regions under the revised ozone standard in 2018. In November 2016, the EPA proposed an implementation rule for the 2015 NAAQS ozone standard, but the agency has yet to issue a final implementation rule. 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. By law, the EPA must review each NAAQS every five years. In December 2018, the EPA announced that it was retaining without significant revision the 2015 NAAQS ozone standard. The EPA has asked for information related to adverse effects that may result from various strategies for attainment and maintenance of NAAQS and is considering re-evaluating the extent to which the EPA can or should consider levels of background ozone when choosing a standard. The EPA expects to conclude the review by October 2020 as required by law. At this time, however, we cannot predict whether state implementation of the 2015 NAAQS ozone standard or the 2020 NAAQS ozone standard would have a material adverse impact on our business, financial condition, results of operations or cash flows.

Texas Commission on Environmental Quality

In January 2011, the 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 time, however, we cannot predict whether any such rules would require us to incur material costs.


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General

New environmental regulations and proposals similar to these, 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

The U.S. Congress has previously considered legislation to restrict or regulate emissions of greenhouse gases, such as carbon dioxide and methane. It presently appears unlikely that comprehensive federal climate legislation will become law in the near future, although energy legislation and other initiatives continue to be proposed that may be relevant to greenhouse gas emissions issues. 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 promulgated 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 one site we operated in 2019.

In addition, the EPA rules provide air permitting requirements for certain large sources of greenhouse gas emissions. The requirement for large sources of greenhouse gas emissions to obtain and comply with permits will affect some of our and our customers’ largest new or modified facilities going forward, but is not expected to cause us to incur material costs.

At the international level, the U.S. joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France, which resulted in an agreement intended to nationally determine their contributions and set greenhouse gas emission reduction goals beginning in 2020. While the Agreement did not impose direct requirements on emitters, national plans to meet its pledge could have resulted in new regulatory requirements. In November 2019, however, President Trump formally announced plans for the U.S. to withdraw from the Paris Agreement with an effective exit date expected in November 2020. The U.S.’s adherence to the exit process is uncertain and the terms on which the U.S. may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time.

Although it is not currently possible to predict how any proposed or future greenhouse gas legislation or regulation promulgated by Congress, the states or multi-state regions will impact our business, any 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.

Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere can change the climate in a manner that results in significant weather-related effects, such as increased frequency and severity of storms, droughts, floods, and other such events. If any of those results occur, it could have an adverse effect on our assets and operations and cause us to incur costs in preparing for and responding to them.

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. Four of our facilities have applied for and obtained industrial wastewater discharge permits and/or have 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.


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Waste Management and Disposal

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, used oil 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 the OSHA and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the safety and health of employees. The OSHA’s hazard communication standard, the EPA’s 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, 2019, we had approximately 1,700 employees. We believe that our relations with our employees are good.

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 any amendments to those reports are available on our website, without charge, as soon as reasonably practicable after they are filed electronically with the SEC. Information on our website is not incorporated by reference in this 2019 Form 10-K or any of our other securities filings. Paper copies of our filings are also available, without charge, from Archrock, Inc., 9807 Katy Freeway, Suite 100, Houston, Texas 77024, Attention: Investor Relations. 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 “Forward-Looking Statements,” this 2019 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 occur, our business, financial condition, results of operations and cash flows could be negatively impacted.

We may not achieve the intended benefits of the Elite Acquisition as and when expected, or at all, which could have an adverse effect on our business.
 
On August 1, 2019, we completed the Elite Acquisition whereby we acquired from Elite Compression substantially all of its assets, liabilities and workforce for aggregate consideration of $214.0 million cash and 21.7 million shares of Archrock common stock. See Note 4 (“Business Transactions”) to our Financial Statements for further details of this transaction.

We now operate a larger combined organization and the difficulties associated with integrating the acquired assets, infrastructure and personnel into our existing operations may require additional time or expense. Our and Elite Compression’s employees may also be uncertain about their future roles within Archrock subsequent to the completion of the Elite Acquisition, which could lead to departures and increased expenses related to hiring and training new employees. Further, we may not realize the benefits we expect to realize from the Elite Acquisition. Any such difficulties could have an adverse effect on our business, results of operations and financial condition.

Further, the acquired business or assets may perform at levels below the levels we anticipated at the time of acquiring such business or assets due to factors beyond our control. As a result, there can be no assurance that the Elite Acquisition will deliver the benefits anticipated by us, and any failure to create such benefits may result in a negative impact to, or material adverse effect on, our business, results of operations, financial condition and cash flows.

The Elite Acquisition resulted in our dependence on Hilcorp for a significant portion of our revenue. The loss of business with Hilcorp or the inability or failure of Hilcorp to meet its payment obligations may adversely affect our financial results.

In connection with the Elite Acquisition, Elite Compression’s contract operations services agreements transferred to us and we expect that Hilcorp, the primary customer of Elite Compression, will account for a significant portion of our future revenue.

During the years ended December 31, 2019, 2018 and 2017, Hilcorp accounted for 3%, 1% and 1% of our revenue, respectively. With the closing of the Elite Acquisition, we estimate that Hilcorp will become one of our most significant customers. Any loss of business from Hilcorp, unless offset by additional contract compression services revenue from other customers, or the inability or failure of Hilcorp to meet its payment obligations could have a material adverse effect on our business, results of operations and financial condition.

Following the closing of the Elite Acquisition, an affiliate of Hilcorp now holds a significant portion of our common stock, and Hilcorp’s interest as an equity holder may conflict with the interests of our other shareholders or our noteholders.

In connection with the closing of the Elite Acquisition, JDH Capital, an affiliate of Hilcorp, received 21.7 million shares of our common stock, representing 14.3% of our outstanding common stock as of December 31, 2019. As long as JDH Capital, together with affiliates of Hilcorp, owns at least 7.5% of our outstanding common stock, it will have the right to nominate one director to our Board of Directors. Given its ownership level and board representation, JDH Capital may have some influence over our operations and strategic direction and may have interests that conflict with the interests of other equity and debt holders.

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 U.S. 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.


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Our ability to use NOLs to offset future income may be limited.

Our ability to use any NOLs generated by us could be substantially limited if we were to experience an “ownership change” as defined under Section 382 of the Code. In general, an “ownership change” would occur if our “5-percent stockholders,” as defined under Section 382 of the Code, including certain groups of persons treated as “5-percent stockholders,” collectively increased their ownership in us by more than 50 percentage points over a rolling three-year period. An ownership change can occur as a result of a public offering of our common stock, as well as through secondary market purchases of our common stock and certain types of reorganization transactions. We have experienced ownership changes, which may result in an annual limitation on the use of its pre-ownership change NOLs (and certain other losses and/or credits) equal to the equity value of our stock immediately before the ownership change, multiplied by the long-term tax-exempt rate for the month in which the ownership change occurs. Such a limitation could, for any given year, have the effect of increasing the amount of our U.S. federal income tax liability, which would negatively impact the amount of after-tax cash available for distribution to our stockholders and our financial condition.

While we paid quarterly dividends of $0.132 per share of common stock with respect to the first and second quarters of 2019 and $0.145 per share with respect to the third and fourth quarters of 2019, there can be no assurance that we will pay dividends in the future.

We paid quarterly cash dividends of $0.132 per share of common stock with respect to the first and second quarters of 2019 and $0.145 per share with respect to the third and fourth quarters of 2019. 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.

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;

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;

our level of operating expenses; and

changes in U.S. federal, state and local income tax laws or corporate laws.

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 cash distributions from the Partnership. As our wholly-owned subsidiary, the Partnership is a significant cash-generating asset for us. As a result, our cash flow is heavily dependent upon the ability of the Partnership to make distributions. Applicable law and contractual restrictions, including restrictions in the Partnership’s debt instruments and partnership agreement and the rights of the creditors of the Partnership that would often be superior to our interests in the Partnership, may negatively impact our ability to obtain such distributions from our subsidiaries. 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 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 debt we may incur in the future and for the funding of our business requirements, which could have a material adverse effect on our business, financial condition and results of operations.

The Partnership has a substantial amount of debt that could limit our and the Partnership’s ability to fund future growth and operations and increase our exposure to risk during adverse economic conditions.

At December 31, 2019 the Partnership had $1.8 billion in outstanding debt obligations, net of unamortized debt discounts and unamortized deferred financing costs. Many factors, including factors beyond our and the Partnership’s control, may affect our ability to make payments on the Partnership’s outstanding indebtedness. These factors include those discussed elsewhere in these Risk Factors.

The Partnership’s 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 on our and the Partnership’s 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 incur indebtedness in the future.

Covenants in the Partnership Debt Agreements may impair our and the Partnership’s ability to operate our respective businesses.

The Partnership Debt Agreements, including the indenture dated as of March 21, 2019 and the indenture dated as of December 20, 2019, pursuant to which we guarantee the 2027 Notes and 2028 Notes on a senior unsecured basis, contain various covenants with which we or certain of our subsidiaries or the Partnership must comply, including, but not limited to, restrictions on the use of proceeds from borrowings, limitations on the incurrence of indebtedness, investments, acquisitions, making loans, liens on assets, repurchasing equity, making dividends or distributions, transactions with affiliates, mergers, consolidations, dispositions of assets and other provisions customary in similar types of agreements. The Partnership Debt Agreements also contain various covenants requiring mandatory prepayments from the net cash proceeds of certain asset transfers. In addition, if as of any date the Partnership has cash and cash equivalents (other than proceeds from a debt or equity issuance in the 30 days prior to such date reasonably expected to be used to fund an acquisition permitted under the Credit Facility) in excess of $50 million, then such excess amount will be used to pay down outstanding borrowings of a corresponding amount under the Credit Facility.


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The Credit Facility is also subject to financial covenants, including the following ratios, as defined in its agreement:

EBITDA to Interest Expense
2.5 to 1.0
Senior Secured Debt to EBITDA
3.5 to 1.0
Total Debt to EBITDA
 
Through fiscal year 2019
5.75 to 1.0
Through second quarter of 2020
5.50 to 1.0
Thereafter (1)
5.25 to 1.0
——————
(1) 
Subject to a temporary increase to 5.5 to 1.0 for any quarter during which an acquisition satisfying certain thresholds is completed and for the two quarters immediately following such quarter.

If the Partnership was to anticipate non-compliance with these financial ratios, the Partnership may take actions to maintain compliance with them. These actions include reductions in its general and administrative expenses, capital expenditures or the payment of cash distributions. Any of these measures, including a reduction in the amount of cash distributions we receive from the Partnership, may reduce the amount of cash available for payment of dividends and the funding of our business requirements, which could have an adverse effect on our business, operations, cash flows or the price of our common stock.

The breach of any of the covenants under the Partnership Debt Agreements, including the Partnership’s financial covenants, could result in a default under the Partnership Debt Agreements, which could cause indebtedness under the Partnership Debt Agreements to become due and payable. If the repayment obligations under the Partnership Debt Agreements were to be accelerated, the Partnership may not be able to repay the debt or refinance the debt on acceptable terms and the Partnership’s financial position would be materially adversely affected. A material adverse effect on the Partnership’s assets, liabilities, financial condition, business or operations, that, taken as a whole, impacts the Partnership’s ability to perform the obligations under the Partnership Debt Agreements could lead to a default under those agreements. Further, a default under one or more of the Partnership Debt Agreements would trigger cross-default provisions under the other Partnership Debt Agreements, which would accelerate the Partnership’s obligation to repay the indebtedness under those agreements.

As of December 31, 2019, the Partnership was in compliance with all covenants under the Partnership Debt Agreements.

Uncertainty relating to the LIBOR calculation process and potential phasing out of LIBOR after 2021 may adversely affect the market value of our current or future debt obligations, including the Partnership’s senior notes and the Credit Facility.

Regulators and law enforcement agencies in the United Kingdom and elsewhere are conducting civil and criminal investigations into whether the banks that contributed to the BBA in connection with the calculation of daily LIBOR may have been under-reporting or otherwise manipulating or attempting to manipulate LIBOR. A number of BBA member banks have entered into settlements with their regulators and law enforcement agencies with respect to this alleged manipulation of LIBOR. Actions by the BBA or any other administrator of LIBOR, regulators or law enforcement agencies may result in changes to the manner in which LIBOR is determined, the phasing out of LIBOR or the establishment of alternative reference rates. For example, on July 27, 2017, the U.K. Financial Conduct Authority announced that it intends to stop persuading or compelling banks to submit LIBOR rates after 2021. As a result, LIBOR may be discontinued by 2021. Furthermore, in the U.S., efforts to identify a set of alternative U.S. dollar reference interest rates that could replace LIBOR include proposals by the Alternative Reference Rates Committee of the Federal Reserve Board and the Federal Reserve Bank of New York. At this time, it is not possible to predict whether any such changes will occur, whether LIBOR will be phased out or any such alternative reference rates or other reforms to LIBOR will be enacted in the United Kingdom, the U.S. or elsewhere or the effect that any such changes, phase out, alternative reference rates or other reforms, if they occur, would have on the amount of interest paid on, or the market value of, our current or future debt obligations, including the Partnership’s senior notes and the Credit Facility. Uncertainty as to the nature of such potential changes, phase out, alternative reference rates or other reforms may materially adversely affect the trading market for LIBOR-based securities, including the Partnership’s senior notes, as well as the terms of the Credit Facility and any interest rate swaps or other derivative agreements to which we are a party. Reform of, or the replacement or phasing out of, LIBOR and proposed regulation of LIBOR and other “benchmarks” may materially adversely affect the market value of, the applicable interest rate on and the amount of interest paid on our current or future debt obligations, including the Partnership’s senior notes and the Credit Facility. In addition, even if we have entered into interest rate swaps or other derivative instruments for purposes of managing our interest rate exposure, our hedging strategies may not be effective as a result of the replacement or phasing out of LIBOR and other “benchmarks” and we may incur substantial losses as a result.


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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 the Credit Facility, we may require additional capital. Periods of instability in the capital and credit markets (both generally and in the oil and gas industry in particular) could limit our ability to access these markets to raise debt or equity capital on affordable terms or to obtain additional financing. Among other things, our lenders may seek 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 us. 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. The supply of experienced operational and field personnel, in particular, decreases as other energy 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.

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, results of operations, financial condition and cash flows. In addition, in the event of the financial failure of a customer, we could experience a loss 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 our and the Partnership’s financial results, which could limit the amount of cash the Partnership has available for distribution to us.

During the years ended December 31, 2019, 2018 and 2017, Williams Partners accounted for 8%, 11% and 13%, respectively, of our revenue. No other customer accounted for 10% or more of our revenue during these years.

There is no guarantee that, upon the expiration of the Partnership’s existing services agreements with Williams Partners, Williams Partners will choose 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 us, and on our business, results of operations, financial condition and ability to pay cash dividends.


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The loss of any of our most significant customers would result in a decline in our revenue and cash available to pay dividends to our common stockholders.

Our five most significant customers collectively accounted for approximately 25%, 26% and 29% of our revenue for the years ended December 31, 2019, 2018 and 2017, respectively. Our services are provided to these customers pursuant to contract compression services agreements, which typically have an initial term of 12 to 60 months and continue thereafter until terminated by either party with 30 days’ advance notice. The loss of all or even a portion of the services we provide to these customers, as a result of competition or otherwise, could have a material adverse effect on our business, results of operations and financial condition.

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 U.S. federal and state tax reporting group between us and Exterran Corporation. If Exterran Corporation is unable to pay any prior period taxes related to these consolidated U.S. federal and state tax filings 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 either occurring as part of a plan or series of related transactions that includes the Spin-off.

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.

Many of our contract operations services contracts have short initial terms and are cancelable on short notice after the initial term, 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 revenue and net income and could require us to record asset impairments. This could have a material adverse effect upon our business, results of operations, financial condition and cash flows.


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We depend on particular suppliers and are vulnerable to product shortages and price increases. With respect to our suppliers of newly-fabricated compression equipment specifically, we occasionally experience long lead times, and therefore may at times make purchases in anticipation of future business. If we are unable to purchase compression equipment (or other integral equipment, materials and services) from third party suppliers, 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.

Some equipment, materials and services used in our business are obtained from a limited group of suppliers. Our reliance on these suppliers involves several risks, including price increases, inferior quality and a potential inability to obtain an adequate supply of such equipment, materials and services in a timely manner. Additionally, we occasionally experience long lead times from our suppliers of newly-fabricated compression equipment and may at times make purchases in anticipation of future business. We do not have long-term contracts with some of these suppliers, and the partial or complete loss of certain of these suppliers could have a negative impact on our results of operations and could damage our customer relationships. Further, a significant increase in the price of such equipment, materials and services could have a negative impact on our results of operations.

If we are unable to purchase compression equipment in particular 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.

Our inability to fund purchases of additional compression equipment could adversely impact our financial results.

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. Cash flow from our operations and availability under our Credit Facility may not provide us with sufficient cash to fund our capital expenditure requirements, including any funding requirements related to acquisitions. Our ability to grow our asset and customer base could be impacted by limits on our ability to access additional capital.

If we do not make acquisitions on economically acceptable terms, our future growth could be limited.

Our ability to grow depends, in part, on our ability to make accretive acquisitions. If we are unable to make accretive acquisitions either because we are (i) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (ii) unable to obtain financing for these acquisitions on economically acceptable terms or (iii) outbid by competitors, then our future growth and ability to maintain distributions could be limited. Furthermore, even if we make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations per unit.

Any acquisition involves potential risks, including, among other things:

an inability to integrate successfully the businesses we acquire;

the assumption of unknown liabilities;

limitations on rights to indemnity from the seller;

mistaken assumptions about the cash generated or anticipated to be generated by the business acquired or the overall costs of equity or debt;

the diversion of management’s attention from other business concerns;

unforeseen operating difficulties; and

customer or key employee losses at the acquired businesses.

If we consummate any future acquisitions, our capitalization and results of operations may change significantly and we will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of our future funds and other resources. In addition, competition from other buyers could reduce our acquisition opportunities or cause us to pay a higher price than we might otherwise pay.

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From time to time, we are subject to various claims, tax audits, litigation and other proceedings that could ultimately be resolved against us and require 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, tax audits, 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 pay dividends. 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 Note 26 (“Commitments and Contingencies”) to our Financial Statements for additional information regarding certain legal proceedings to which we are a party.

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. Our competitors may be able to more quickly adapt to technological changes within our industry and changes in economic and market conditions as a whole, 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 compressors that would create additional competition for the services we provide to our customers. In addition, our customers may purchase and operate their own compression 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, results of operations and financial condition.

We may be vulnerable to interest rate increases due to our variable rate debt obligations.

As of December 31, 2019, after taking into consideration interest rate swaps, we had $113.0 million of outstanding indebtedness that was effectively subject to variable 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 variable interest rates at December 31, 2019 would result in an annual increase in our interest expense of $1.1 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 us and as a result negatively impact our results of operations and cash flows, including our ability to pay dividends in the future.

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. Our insurance coverage includes property damage, general liability and commercial automobile liability and other coverage we believe is appropriate. 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. We are also self-insured for property damage to our offshore assets. 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, results of operations and financial condition could be negatively impacted.


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We may not realize the intended benefits of our recent technology transformation project, which could have an adverse effect on our business.

In the fourth quarter of 2018, we began a process and technology transformation project that will, among other things, upgrade or replace our existing ERP, supply chain and inventory management systems and expand the remote monitoring capabilities of our compression fleet. By using technology to make our systems and processes more efficient, we intend to lower our internal costs and improve our profitability over time. However, the implementation of the technology transformation project requires capital and other resources. We expensed $6.3 million in 2019 related to this project, and we anticipate that the project will continue to require significant resources and will result in increased SG&A expense and capital expenditures for the implementation of new technologies in 2020. Further, we may not realize the benefits we expect to realize from the technology transformation project. Any such difficulties could have an adverse effect on our business, results of operations and financial condition.

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, results of operations and financial condition.

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.

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. We do not perform hydraulic fracturing, but many of our customers do. 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.

For example, at the U.S. federal level, the 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 BLM 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 never went into effect due to pending litigation and on December 28, 2017, the BLM announced that it had rescinded the 2015 final rule, in part citing a review that found that 32 of the 32 states with federal oil and gas leases have regulations that already address hydraulic fracturing.

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.

24



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

On June 3, 2016, the EPA issued final regulations amending the NSPS for the oil and natural gas source category and applying to sources of emissions of methane and VOC from certain processes, activities and equipment that is constructed, modified or reconstructed after September 18, 2015. Specifically, the regulation contains both methane and VOC standards for several emission sources not previously 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 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. In June 2017, the EPA proposed and took public comment on a two-year stay of the fugitive emissions requirements, well site pneumatic standards and closed vent certification. The EPA sought additional comment in November 2017 in support of the proposed rule, but has not finalized the two-year stay. In October 2018 and August 2019, the EPA proposed deregulatory amendments to the 2016 rule intended to streamline implementation, reduce duplicative EPA and state requirements and decrease the burden of compliance. The EPA has not yet issued a final rule based on either proposal. At this time, we do not believe that if finalized these rules will have a material adverse impact on our business, financial condition, results of operations or cash flows.

On November 18, 2016, the BLM published final rules to reduce venting and flaring on federal and tribal lands. The rules set forth some novel requirements regarding leak detection inspections at compressor stations and imposed requirements to reduce emissions from pneumatic controllers and pumps, among other things. In December 2017, the BLM finalized suspension of certain requirements of the November 2016 final rule until January 2019. In September 2018, the BLM finalized a rule rescinding the novel requirements pertaining to waste-minimization plans, gas-capture percentages, well drilling, well completion and related operations, pneumatic controllers, pneumatic diaphragm pumps, storage vessels and leak detection and repair. The BLM also revised other provisions related to venting and flaring. California, New Mexico and various environmental groups filed a lawsuit challenging the September 2018 final rule, which is still pending.

On October 1, 2015, the EPA issued a new NAAQS ozone standard of 70 ppb, which is a reduction from the 75 ppb standard set in 2008. This new standard became effective on December 28, 2015, and the EPA completed designating attainment/non-attainment regions under the revised ozone standard in 2018. In November 2016, the EPA proposed an implementation rule for the 2015 NAAQS ozone standard, but the agency has yet to issue a final implementation rule. 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. By law, the EPA must review each NAAQS every five years. In December 2018, the EPA announced that it was retaining without significant revision the 2015 NAAQS ozone standard. The EPA has asked for information related to adverse effects that may result from various strategies for attainment and maintenance of NAAQS and is considering re-evaluating the extent to which the EPA can or should consider levels of background ozone when choosing a standard. The EPA expects to conclude the review by October 2020 as required by law. At this time, however, we cannot predict whether state implementation of the 2015 NAAQS ozone standard or the 2020 NAAQS ozone standard would have a material adverse impact on our business, financial condition, results of operations or cash flows.

In January 2011, the 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 time, however, we cannot predict whether any such rules would require us to incur material costs.

New environmental regulations and proposals similar to these, 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.


25


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, including relating to the environment, health and safety, 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. From time to time, as part of our operations, including newly acquired operations, we may be subject to compliance audits by regulatory authorities in the various states in which we operate.

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.

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. It presently appears unlikely that comprehensive federal climate legislation will become law in the near future, although energy legislation and other initiatives continue to be proposed that may be relevant to greenhouse gas emissions issues. 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.

26



Independent of Congress, the EPA has promulgated 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 one site we operated in 2019.

In addition, the EPA rules provide air permitting requirements for certain large sources of greenhouse gas emissions. The requirement for large sources of greenhouse gas emissions to obtain and comply with permits will affect some of our and our customers’ largest new or modified facilities going forward, but is not expected to cause us to incur material costs.

At the international level, the U.S. joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France, which resulted in an agreement intended to nationally determine their contributions and set greenhouse gas emission reduction goals every five years beginning in 2020. While the Agreement did not impose direct requirements on emitters, national plans to meet its pledge could have resulted in new regulatory requirements. In November 2019, however, President Trump formally announced plans to withdraw from the Paris Agreement with an effective exit date expected in November 2020. The U.S.’s adherence to the exit process is uncertain and the terms on which the U.S. may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time.

Although it is not currently possible to predict how any proposed or future greenhouse gas legislation or regulation promulgated by Congress, the states or multi-state regions will impact our business, any 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.

Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere can change the climate in a manner that results in significant weather-related effects, such as increased frequency and severity of storms, droughts, floods, and other such events. If any of those results occur, it could have an adverse effect on our assets and operations and cause us to incur costs in preparing for and responding to them.

Item 1B. Unresolved Staff Comments

None.


27


Item 2. Properties

The following table describes the material facilities we owned or leased at December 31, 2019:

Location
 
Status
 
Square Feet
 
Use by Segment
Houston, Texas
 
Leased
 
77,000
 
Corporate office - Contract Operations and Aftermarket Services
Nunn, Colorado
 
Leased
 
5,000
 
Contract Operations and Aftermarket Services
Rifle, Colorado
 
Leased
 
10,000
 
Contract Operations and Aftermarket Services
McPherson, Kansas
 
Owned
 
28,000
 
Aftermarket Services
Broussard, Louisiana
 
Owned
 
89,000
 
Contract Operations and Aftermarket Services
Houma, Louisiana
 
Owned
 
60,000
 
Contract Operations and Aftermarket Services
Gaylord, Michigan
 
Leased
 
13,000
 
Contract Operations and Aftermarket Services
Farmington, New Mexico
 
Owned
 
62,000
 
Contract Operations and Aftermarket Services
Oklahoma City, Oklahoma
 
Leased
 
41,000
 
Contract Operations and Aftermarket Services
Yukon, Oklahoma
 
Owned
 
85,000
 
Contract Operations and Aftermarket Services
Asherton, Texas
 
Leased
 
9,000
 
Contract Operations and Aftermarket Services
Brenham, Texas
 
Owned
 
10,000
 
Contract Operations and Aftermarket Services
Cotulla, Texas
 
Leased
 
10,000
 
Contract Operations and Aftermarket Services
Fort Worth, Texas
 
Leased
 
49,000
 
Contract Operations and Aftermarket Services
Karnes City, Texas
 
Leased
 
4,000
 
Contract Operations and Aftermarket Services
Marshall, Texas
 
Leased
 
11,000
 
Contract Operations and Aftermarket Services
Midland, Texas
 
Owned
 
51,000
 
Contract Operations and Aftermarket Services
Pecos, Texas
 
Leased
 
10,000
 
Contract Operations and Aftermarket Services
Victoria, Texas
 
Owned
 
23,000
 
Contract Operations and Aftermarket Services
Victoria, Texas
 
Owned
 
66,000
 
Contract Operations and Aftermarket Services
Bridgeport, West Virginia
 
Leased
 
17,000
 
Contract Operations and Aftermarket Services
Evansville, Wyoming
 
Leased
 
15,000
 
Contract Operations and Aftermarket Services
Rock Springs, Wyoming
 
Leased
 
9,000
 
Contract Operations and Aftermarket Services
 

Our executive office is located at 9807 Katy Freeway, Suite 100, Houston, Texas 77024 and our telephone number is 281-836-8000.

Item 3. Legal Proceedings

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, we believe that any ultimate liability arising from any of these actions will not have a material adverse effect on our consolidated financial position, results of operations or cash flows, including our ability to pay dividends. 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, including our ability to pay dividends.

Item 4. Mine Safety Disclosures
 
Not applicable.

28


PART II

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

Common Stock

Our common stock is traded on the New York Stock Exchange under the symbol “AROC.”  

The performance graph below shows the cumulative total stockholder return on our common stock compared with the S&P 500 and AMNAX indices over the five-year period beginning on December 31, 2014. The results are based on an investment of $100 in each of our common stock, the S&P 500 and the AMNAX. The graph assumes reinvestment of dividends and adjusts all closing prices and dividends for stock splits.

Comparison of Five Year Cumulative Total Return
chart-3614b7643ab101840be.jpg
The performance graph shall not be deemed incorporated by reference by any general statement incorporating by reference this 2019 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.

Holders

On February 13, 2020, the closing price of our common stock was $8.40 per share. As of February 13, 2020, there were approximately 1,053 holders of record of our common stock. The actual number of stockholders is greater than this number of record holders and includes stockholders who are beneficial owners but whose shares are held in street name by banks, brokers and other nominees.

Unregistered Sales of Equity Securities and Use of Proceeds

None.


29


Repurchase of Equity Securities

None.

Item 6. Selected Financial Data

The table below shows selected financial data for Archrock for each of the five years in the period ended December 31, 2019, which has been derived from our audited Financial Statements. The following information should be read together with Management’s Discussion and Analysis of Financial Condition and Results of Operations and the Financial Statements contained in this 2019 Form 10-K (in thousands, except per share data).

 
Year Ended December 31,
 
2019 (1)(2)
 
2018 (1)
 
2017
 
2016
 
2015
Statement of Operations Data:
 
 
 
 
 
 
 

 
 

Revenue
$
965,485

 
$
904,441

 
$
794,655

 
$
807,069

 
$
998,108

Income (loss) from continuing operations (3)
97,603

 
29,160

 
18,464

 
(64,817
)
 
(159,374
)
Income (loss) from discontinued operations, net of tax (4)
(273
)
 

 
(54
)
 
(426
)
 
33,677

Net income (loss) attributable to the noncontrolling interest

 
8,097

 
(543
)
 
(10,688
)
 
6,852

Net income (loss) attributable to Archrock stockholders (3)
97,330

 
21,063

 
18,953

 
(54,555
)
 
(132,549
)
Net income (loss) from continuing operations attributable to Archrock stockholders per common share: basic and diluted
0.70

 
0.19

 
0.26

 
(0.79
)
 
(2.44
)
 
 
 
 
 
 
 
 
 
 
Balance Sheet Data:
 
 
 
 
 

 
 

 
 

Working capital (5)
$
93,460

 
$
105,454

 
$
90,307

 
$
109,157

 
$
150,199

Total assets
3,109,975

 
2,552,515

 
2,408,007

 
2,414,779

 
2,695,180

Long-term debt
1,842,549

 
1,529,501

 
1,417,053

 
1,441,724

 
1,576,882

Total Archrock stockholders’ equity
1,085,963

 
841,574

 
777,049

 
718,966

 
733,910

 
 
 
 
 
 
 
 
 
 
Other Financial Data:
 
 
 
 
 
 
 
 
 
Capital expenditures
$
385,198

 
$
319,102

 
$
221,693

 
$
117,572

 
$
256,142

Dividends declared and paid per common share
0.5540

 
0.5040

 
0.4800

 
0.4975

 
0.6000

——————
(1) 
Amounts reported for 2019 and 2018 are per our adoption of ASC 606 Revenue on January 1, 2018. Comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods.
(2) 
Amounts reported for 2019 are per our adoption of ASC 842 Leases on January 1, 2019. Comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods.
(3) 
In 2019, included a $50.8 million one-time benefit from the release of a deferred tax asset valuation allowance, a $44.7 million long-lived asset impairment charge and a $16.0 million gain on sale of assets. In 2018, included a $28.1 million long-lived asset impairment charge. In 2017, included a $53.4 million tax benefit as the result of the TCJA and a $29.1 million long-lived asset impairment charge. In 2016, included an $87.4 million long-lived asset impairment charge and $16.9 million of restatement and other charges. In 2015, included a $125.0 million long-lived asset impairment charge and $86.0 million of valuation allowances and foreign tax credit write-offs as the result of the Spin-off.
(4) 
Income from discontinued operations in 2015 was the result of the Spin-off.
(5) 
Defined as current assets minus current liabilities.


30


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 2019 Form 10-K. The following discussion includes forward-looking statements that involve certain risks and uncertainties. See “Forward-Looking Statements” and Part I, Item 1A “Risk Factors” in this 2019 Form 10-K.
Overview

We are an energy infrastructure company with a pure-play focus on midstream natural gas compression. We are 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 business supports a must-run service that is essential to the production, processing, transportation and storage of natural gas. Our geographic diversity, technically experienced personnel and large fleet of natural gas compression equipment enable us to provide reliable contract operations services to our customers.

We operate in two business segments:

Contract Operations. Our contract operations business is comprised of 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 our customers that own compression equipment, including operations, maintenance, overhaul and reconfiguration services and sales of parts and components.

Recent Business Developments

2028 Notes Offering

On December 20, 2019, we completed a private offering of $500.0 million aggregate principal amount of 6.25% senior notes due April 2028. We received net proceeds of $491.8 million after issuance costs, which were used to repay borrowings outstanding under our Credit Facility. See Note 13 (“Long-Term Debt”) to our Financial Statements for further details of this transaction.

Amendment to the Credit Facility

On November 8, 2019, we entered into Amendment No. 2, which extended the maturity date of, and changed the applicable margins for borrowings under, our Credit Facility. See Part II Item 7 “Liquidity and Capital Resources — Financial Resources” and Note 13 (“Long-Term Debt”) to our Financial Statements for further details of this amendment.

Elite Acquisition

On August 1, 2019, we completed the Elite Acquisition whereby we acquired from Elite Compression substantially all of its assets, including a fleet of predominantly large compressors comprising approximately 430,000 horsepower, vehicles, real property and inventory, and certain liabilities for aggregate consideration consisting of $214.0 million in cash and 21.7 million shares of common stock with an acquisition date fair value of $225.9 million. The cash portion of the acquisition was funded with borrowings on the Credit Facility.

Harvest Sale

On August 1, 2019, we completed an asset sale in which Harvest acquired from us approximately 80,000 active and idle compression horsepower, vehicles and parts inventory for cash consideration of $30.0 million. We recorded a $6.6 million gain on the sale of these assets during 2019.

See Note 4 (“Business Transactions”) to our Financial Statements for further details of the Elite Acquisition and the Harvest Sale.


31


2027 Notes Offering and 2021 Notes Extinguishment

On March 21, 2019, we completed a private offering of $500.0 million aggregate principal amount of 6.875% senior notes due April 2027. We received net proceeds of $491.2 million after issuance costs, which were used to repay borrowings outstanding under our Credit Facility.

On April 5, 2019, we repaid the 2021 Notes with borrowings from our Credit Facility.

See Note 13 (“Long-Term Debt”) to our Financial Statements for further details of these transactions.

Trends and Outlook

The key driver of our business is the production of U.S. crude oil and natural gas. Approximately 70% of our operating fleet is deployed for midstream applications with the remaining fleet being used in wellhead and gas lift applications to enhance oil production. Changes in oil and natural gas production spending therefore typically result in changes in demand for our services. Spending on oil and natural gas exploration and production typically declines when there is a significant and prolonged reduction in oil and natural gas prices or significant instability in energy markets and increases during periods of rising prices and market stability. As our business is so closely aligned with production and is typically less directly impacted by commodity prices, we are not exposed to the volatility often faced in shorter-cycle oil field service businesses.
 
Increased global demand for U.S. oil and natural gas production in recent years has contributed to increased production for both resources and record U.S. natural gas production in 2018 and 2019. According to the EIA, average U.S. dry natural gas and crude oil production in 2019, 2018 and 2017 were as follows:
 
Year Ended December 31,
 
2019
 
2018
 
2017
Average dry natural gas production (Bcf/d)
92.0

 
83.8

 
74.8

Average crude oil production (MMb/d)
12.2

 
11.0

 
9.4


These increases in production resulted in strong demand for our compression services in 2019 and 2018. Additionally, we increased our investment in new fleet units in each of 2019, 2018 and 2017 to take advantage of improved market conditions. As a result of this increased demand and investment, our contract operations revenue and average operating horsepower increased 15% and 10%, respectively, in 2019 compared to 2018 and 10% and 7%, respectively, in 2018 compared to 2017.

The EIA forecasts the following year-over-year changes in its January 2020 Short-Term Energy Outlook report:
 
2020
 
2021
Dry natural gas production
3
%
 
(1
)%
Liquefied natural gas exports
30
%
 
19
 %
Crude oil production
9
%
 
3
 %

Long term, the EIA expects dry natural gas production to increase 10% through 2024. We believe that the abundance and economics of U.S. shale and relative price stability of natural gas in the U.S. will continue to drive demand for U.S. natural gas for liquefied natural gas exports, natural gas exports via pipeline to Mexico and natural gas use in power generation and as a petrochemical feedstock. We expect that such an increase in demand for U.S. natural gas will in turn lead to continued strong demand for compression services.

We anticipate that the horsepower acquired in the Elite Acquisition, together with continued strong demand for compression services, will help to maintain our high utilization and result in an increase in revenue in 2020 as compared to 2019 and 2018 in our contract operations business. In our aftermarket services business, though activity levels decreased in 2019, the base of owned compression in the U.S. has increased over the past several years, which we believe will help sustain our aftermarket services business over the long term.

32


Certain Key Challenges and Uncertainties

In addition to general market conditions in the oil and natural gas industry and competition in the natural gas compression industry, we believe the following represent some of the key challenges and uncertainties we will face in the future.

Capital Requirements and the Availability of External Sources of Capital. We funded a significant portion of our capital expenditures and the cash portion of the Elite Acquisition through borrowings under the Credit Facility and issued additional debt such that we now have a substantial amount of debt, which could limit our ability to fund future planned capital expenditures. Current conditions could limit our ability to access the debt and equity markets to raise capital on affordable terms in 2020 and beyond. If we are not successful in raising capital within the time period required or at all, we may not be able to fund these capital expenditures, which could impair our ability to grow or maintain our business.

Cost Management. In 2020, we will likely face rising costs due to manufacturer price increases and higher labor costs due to low unemployment rates in many of our operating areas. To address rising costs, we are actively working to retain employees, negotiating sourcing agreements with vendors and passing cost increases through to customers where appropriate.

In addition, in order to improve our operations, in the fourth quarter of 2018 we began a process and technology transformation project that will, among other things, upgrade or replace our existing ERP, supply chain and inventory management systems and expand the remote monitoring capabilities of our compression fleet. We believe these improvements will reduce our operating costs and increase our uptime. We expensed $6.3 million in 2019 related to this project, and we anticipate that the project will continue to require significant resources and result in increased SG&A expense and capital expenditures for the implementation of new technologies in 2020.

Cost management continues to be challenging and there is no guarantee that our efforts will result in a reduction in our operating expenses. Continued natural gas production growth and resulting demand for our services could also cause us to experience increased operating expenses as we hire employees and incur additional expenses needed to support the market demand.

Labor. 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. 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.

Later-Cycle Market Participant. Compression service providers have traditionally been a later-cycle participant as energy markets fluctuate. As such, we anticipate that any significant change in the demand for our contract operations services will generally lag a change in drilling activity. Increased oil and natural gas production in 2017, 2018 and 2019 contributed to increased new orders for our compression services in 2017 and 2018. Despite these new orders, revenue gains were not realized until 2018 and 2019 as the operating horsepower declines and pricing pressure experienced prior to 2017 resulted in a decline in our revenue in 2017. Dry natural gas production, one of the key drivers of our business, increased 12% in 2018 and 10% in 2019 and is expected to increase 10% in 2020 through 2024. We believe this production growth will continue to increase demand for compression services, which we expect will result in continued increases in revenue and gross margin, though on a lag of several quarters or more.

Customer deferrals. Our aftermarket services revenue decreased in 2019 as customers deferred near-term maintenance activities. We believe the large installed base of owned compression supports the long-term fundamentals of the aftermarket services business: however, the timing of a recovery is difficult to predict. We remain focused on cost management and the higher margin business within our aftermarket services operations.

Increasing customer focus on free cash flow. Many of our customers are transitioning their business model to focus on sustainable free cash flow generation rather than growth. We expect this transition to have a positive impact on the industry in the long term, as we anticipate the change will reduce volatility through cycles and improve the financial strength of our customers. In the near term, however, we can expect this transition to result in a deceleration in the natural gas production growth rate, to which demand for our products and services is closely aligned.


33


Operating Highlights

The following table summarizes our available and operating horsepower and horsepower utilization (in thousands, except percentages):
 
Year Ended December 31,
 
2019
 
2018
 
2017
Total available horsepower (at period end) (1)
4,395

 
3,963

 
3,847

Total operating horsepower (at period end) (2)
3,926

 
3,530

 
3,253

Average operating horsepower
3,708

 
3,386

 
3,152

Horsepower utilization:


 


 
 
Spot (at period end)
89
%
 
89
%
 
85
%
Average
88
%
 
87
%
 
82
%
——————
(1) 
Defined as idle and operating horsepower. New compressors completed by a third party manufacturer that have been delivered to us are included in the fleet.
(2) 
Defined as horsepower that is operating under contract and horsepower that is idle but under contract and generating revenue such as standby revenue.

Non-GAAP Financial Measures
Management uses a variety of financial and operating metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include the non-GAAP financial measure of gross margin.
We define gross margin as total revenue less cost of sales (excluding depreciation and amortization). 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), 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 SG&A activities, our financing methods and income taxes. In addition, depreciation and amortization may not accurately reflect the costs required to maintain and replenish the operational usage of our assets and therefore may not portray the costs of 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 GAAP. Our gross margin may not be comparable to a similarly-titled measure of other entities 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 SG&A, depreciation and amortization, impairments, restatement and other charges, restructuring and other charges, interest expense, debt extinguishment loss, transaction-related costs, gain (loss) on sale of assets, net, other income (loss), net, provision for (benefit from) income taxes and loss from discontinued operations, net of tax. 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 is 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.


34


The following table reconciles net income to gross margin (in thousands):
 
Year Ended December 31,
 
2019
 
2018
 
2017
Net income
$
97,330

 
$
29,160

 
$
18,410

Selling, general and administrative
117,727

 
101,563

 
111,483

Depreciation and amortization
188,084

 
174,946

 
188,563

Long-lived asset impairment
44,663

 
28,127

 
29,142

Restatement and other charges
445

 
19

 
4,370

Restructuring and other charges

 

 
1,386

Interest expense
104,681

 
93,328

 
88,760

Debt extinguishment loss
3,653

 
2,450

 
291

Transaction-related costs
8,213

 
10,162

 
275

Gain on sale of assets, net
(16,016
)
 
(5,674
)
 
(5,675
)
Other income, net
(661
)
 
(157
)
 
(243
)
Provision for (benefit from) income taxes
(39,145
)
 
6,150

 
(61,083
)
Loss from discontinued operations, net of tax
273

 

 
54

Gross margin
$
509,247

 
$
440,074

 
$
375,733


Financial Results of Operations
 
Summary of Results
 
Revenue. Revenue was $965.5 million, $904.4 million and $794.7 million during the years ended December 31, 2019, 2018 and 2017, respectively.

The increase in revenue during the year ended December 31, 2019 compared to the year ended December 31, 2018 was due to an increase in revenue from our contract operations business, partially offset by a decrease in revenue from our aftermarket services business. The increase in revenue during the year ended December 31, 2018 compared to the year ended December 31, 2017 was due to increases in revenue from our contract operations and aftermarket services businesses.

See “Contract Operations” and “Aftermarket Services” below for further details.

Net income attributable to Archrock stockholders. We generated net income attributable to Archrock stockholders of $97.3 million, $21.1 million and $19.0 million during the years ended December 31, 2019, 2018 and 2017, respectively.

The increase in net income attributable to Archrock stockholders during the year ended December 31, 2019 compared to the year ended December 31, 2018 was primarily driven by an increase in gross margin from our contract operations business, the change in provision for (benefit from) income taxes, an increase in gain on sale of assets, net and the decrease in net income attributable to the noncontrolling interest, partially offset by increases in long-lived asset impairment, SG&A, depreciation and amortization and interest expense.

The increase in net income attributable to Archrock stockholders during the year ended December 31, 2018 compared to the year ended December 31, 2017 was primarily driven by the increase in gross margin from our contract operations and aftermarket services businesses and decreases in depreciation and amortization, SG&A and restatement and other charges, partially offset by the change in provision for (benefit from) income taxes, transaction-related costs, the change in net income (loss) attributable to the noncontrolling interest and an increase in interest expense.


35


Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

Contract Operations
(dollars in thousands)
 
Year Ended December 31,
 
Increase
 
2019
 
2018
 
(Decrease)
Revenue
$
771,539

 
$
672,536

 
15
%
Cost of sales (excluding depreciation and amortization)
297,260

 
273,013

 
9
%
Gross margin
$
474,279

 
$
399,523

 
19
%
Gross margin percentage(1)
61
%
 
59
%
 
2
%
——————
(1) 
Defined as gross margin divided by revenue.

The increase in revenue during the year ended December 31, 2019 compared to the year ended December 31, 2018 was primarily due to an increase in contract operations rates driven by an increase in customer demand, an increase in average operating horsepower (excluding the horsepower acquired in the Elite Acquisition) and $33.2 million of revenue associated with the compression assets acquired in the Elite Acquisition.

Gross margin increased during the year ended December 31, 2019 compared to the year ended December 31, 2018 primarily due to the increase in revenue mentioned above partially offset by the increase in cost of sales. The increase in cost of sales was primarily driven by increases in maintenance, freight and lube oil expense associated with the increase in average operating horsepower and the horsepower acquired in the Elite Acquisition. These increases in cost of sales were partially offset by a decrease in cost associated with the start-up of compression packages, as the majority of the increase in average operating horsepower was comprised of newly-built compressors.

Gross margin percentage increased during the year ended December 31, 2019 compared to the year ended December 31, 2018 primarily due to the increase in contract operations rates mentioned above.

Aftermarket Services
(dollars in thousands)
 
Year Ended December 31,
 
Increase
 
2019
 
2018
 
(Decrease)
Revenue
$
193,946

 
$
231,905

 
(16
)%
Cost of sales (excluding depreciation and amortization)
158,978

 
191,354

 
(17
)%
Gross margin
$
34,968

 
$
40,551

 
(14
)%
Gross margin percentage
18
%
 
17
%
 
1
 %

The decrease in revenue during the year ended December 31, 2019 compared to the year ended December 31, 2018 was primarily due to decreases in parts sales and service activities as customers deferred maintenance activities.

Gross margin decreased during the year ended December 31, 2019 compared to the year ended December 31, 2018 due to the decrease in revenue mentioned above, partially offset by a smaller decrease in cost of sales. The decrease in cost of sales was primarily driven by the decrease in parts sales and service activities.


36


Costs and Expenses
(dollars in thousands)
 
Year Ended December 31,
 
2019
 
2018
Selling, general and administrative
$
117,727

 
$
101,563

Depreciation and amortization
188,084

 
174,946

Long-lived asset impairment
44,663

 
28,127

Restatement and other charges
445

 
19

Interest expense
104,681

 
93,328

Debt extinguishment loss
3,653

 
2,450

Transaction-related costs
8,213

 
10,162

Gain on sale of assets, net
(16,016
)
 
(5,674
)
Other income, net
(661
)
 
(157
)

Selling, general and administrative. The increase in SG&A expense during the year ended December 31, 2019 compared to the year ended December 31, 2018 was primarily due to a $9.2 million increase in sales and use tax expense primarily resulting from the settlement of audits in 2018, a $4.1 million increase in costs related to our process and technology transformation project and a $2.7 million increase in compensation and benefits.

Depreciation and amortization. The increase in depreciation and amortization expense during the year ended December 31, 2019 compared to the year ended December 31, 2018 was primarily due to an increase in depreciation expense associated with fixed asset additions, which was partially offset by a decrease in expense from assets reaching the end of their useful lives, asset retirements and the impact of asset impairments during 2018 and 2019. The increase in depreciation expense was partially offset by a decrease in amortization expense that primarily resulted from certain intangible assets reaching the end of their useful lives, partially offset by amortization expense related to the intangible assets acquired in the Elite Acquisition.

Long-lived asset impairment. During the years ended December 31, 2019 and 2018, we reviewed the future deployment of our idle compressors for units that were not of the type, configuration, condition, make or model that are cost efficient to maintain and operate. In addition, we evaluated for impairment idle units that had been culled from our fleet in prior years and were available for sale. See Note 17 (“Long-Lived Asset Impairment”) to our Financial Statements for further details.

The following table presents the results of our impairment review, as recorded to our contract operations segment (dollars in thousands):
 
Year Ended December 31,
 
2019
 
2018
Idle compressors retired from the active fleet
975

 
310

Horsepower of idle compressors retired from the active fleet
170,000

 
115,000

Impairment recorded on idle compressors retired from the active fleet
$
44,663

 
$
28,127


Restatement and other charges. During the years ended December 31, 2019 and 2018, we recorded expense of $0.4 million and $1.3 million, respectively, for our share of professional and legal fees related to the restatement of prior period financial statements and disclosures and related matters. We recorded $1.3 million for the expected recovery of shared fees incurred during the year ended December 31, 2018.

Interest expense. The increase in interest expense during the year ended December 31, 2019 compared to the year ended December 31, 2018 was primarily due to an increase in the average outstanding balance of long-term debt, partially offset by a decrease in the weighted average effective interest rate.

Debt extinguishment loss. We recorded a debt extinguishment loss of $3.7 million during the year ended December 31, 2019 as a result of the redemption of the 2021 Notes. We recorded a debt extinguishment loss of $2.5 million during the year ended December 31, 2018 as a result of the termination of the Archrock Credit Facility. See Note 13 (“Long-Term Debt”) to our Financial Statements for further details.


37


Transaction-related costs. We incurred $8.2 million and $10.2 million of financial advisory, legal and other professional fees during the years ended December 31, 2019 and 2018, respectively. The $8.2 million of fees incurred during the year ended December 31, 2019 related primarily to the Elite Acquisition. The $10.2 million of fees incurred during the year ended December 31, 2018 related to the Merger. See Note 4 (“Business Transactions”) and Note 15 (“Equity”) to our Financial Statements for further details of these transactions.

Gain on sale of assets, net. The increase in gain on sale of assets, net was primarily due to a $6.6 million gain related to the Harvest Sale during the year ended December 31, 2019 and a $3.2 million increase in gains recognized on other compression equipment sales during the year ended December 31, 2019 compared to the year ended December 31, 2018. See Note 4 (“Business Transactions”) for further details of the Harvest Sale.

Other income, net. The increase in other income, net during the year ended December 31, 2019 compared to the year ended December 31, 2018 was primarily due to a $0.9 million decrease in indemnification expense incurred pursuant to our tax matters agreement with Exterran Corporation and income of $0.3 million related to equipment damaged at a customer site during 2019, partially offset by $0.5 million in indemnification income earned pursuant to that same tax matters agreement during 2018 and a $0.3 million decrease in interest income earned related to tax refunds and settlements.

Provision for (Benefit from) Income Taxes
(dollars in thousands)
 
Year Ended December 31,
 
Increase
 
2019

2018
 
(Decrease)
Provision for (benefit from) income taxes
$
(39,145
)
 
$
6,150

 
(737
)%
Effective tax rate
(67
)%
 
17
%
 
(84
)%

The change in provision for (benefit from) income taxes was primarily due to the release of a valuation allowance in the year ended December 31, 2019, as well as a higher release of an unrecognized tax benefit due to the settlement of a tax audit in the year ended December 31, 2019 compared to the year ended December 31, 2018. See Note 20 (“Income Taxes”) to our Financial Statements for further details.

Net Income Attributable to the Noncontrolling Interest
(dollars in thousands)
 
Year Ended December 31,
 
Increase
 
2019
 
2018
 
(Decrease)
Net income attributable to the noncontrolling interest
$

 
$
(8,097
)
 
(100
)%

Net income attributable to the noncontrolling interest was the portion of the Partnership’s earnings that were applicable to the Partnership’s publicly-held common unitholder interest through the completion of the Merger. Immediately prior to the Merger, public unitholders held a 57% ownership interest in the Partnership. Subsequent to the Merger, the Partnership is a wholly-owned subsidiary. See Note 15 (“Equity”) to our Financial Statements for further details of the Merger.


38


Year Ended December 31, 2018 Compared to Year Ended December 31, 2017

Contract Operations
(dollars in thousands)
 
Year Ended December 31,
 
Increase
 
2018
 
2017
 
(Decrease)
Revenue
$
672,536

 
$
610,921

 
10
%
Cost of sales (excluding depreciation and amortization)
273,013

 
263,005

 
4
%
Gross margin
$
399,523

 
$
347,916

 
15
%
Gross margin percentage
59
%
 
57
%
 
2
%

The increase in revenue during the year ended December 31, 2018 compared to the year ended December 31, 2017 was primarily due to a 7% increase in average operating horsepower and an increase in contract operations rates driven by an increase in customer demand. The increase in revenue was partially offset by the deferral of rebillable freight revenue as a result of the adoption of the Revenue Recognition Update.

Gross margin increased during the year ended December 31, 2018 compared to the year ended December 31, 2017 primarily due to the increase in revenue mentioned above partially offset by the increase in cost of sales. The increase in cost of sales was primarily driven by increases in maintenance expense and lube oil expense associated with the increase in average operating horsepower. These increases were partially offset by decreases in freight expense and expense associated with the mobilization of compression packages as a result of the capitalization and amortization of the portion of these costs that were incurred prior to the transfer of service in accordance with the adoption of the Revenue Recognition Update.

Gross margin percentage increased during the year ended December 31, 2018 compared to the year ended December 31, 2017 primarily due to the increase in rates and the capitalization of costs incurred to fulfill contracts prior to the transfer of service as a result of the adoption of the Revenue Recognition Update.


Aftermarket Services
(dollars in thousands)
 
Year Ended December 31,
 
Increase
 
2018
 
2017
 
(Decrease)
Revenue
$
231,905

 
$
183,734

 
26
%
Cost of sales (excluding depreciation and amortization)
191,354

 
155,917

 
23
%
Gross margin
$
40,551

 
$
27,817

 
46
%
Gross margin percentage
17
%
 
15
%
 
2
%

The increase in revenue during the year ended December 31, 2018 compared to the year ended December 31, 2017 was primarily due to increases in service activities and part sales driven by increased customer demand as well as the change to recognize revenue for service activities over time as a result of the adoption of the Revenue Recognition Update.

Gross margin increased during the year ended December 31, 2018 compared to the year ended December 31, 2017 due to the increase in revenue mentioned above partially offset by the increase in cost of sales. The increase in cost of sales was primarily driven by the increase in service activities and part sales as well as the change to recognize costs associated with service activities over time as a result of the adoption of the Revenue Recognition Update.

Gross margin percentage increased during the year ended December 31, 2018 compared to the year ended December 31, 2017 primarily due to higher billable labor utilization as a result of the increase in activity mentioned above.



39


Costs and Expenses
(dollars in thousands)

 
Year Ended December 31,
 
2018
 
2017
Selling, general and administrative
$
101,563

 
$
111,483

Depreciation and amortization
174,946

 
188,563

Long-lived asset impairment
28,127

 
29,142

Restatement and other charges
19

 
4,370

Restructuring and other charges

 
1,386

Interest expense
93,328

 
88,760

Debt extinguishment loss
2,450

 
291

Transaction-related costs
10,162

 
275

Gain on sale of assets, net
(5,674
)
 
(5,675
)
Other income, net
(157
)
 
(243
)

Selling, general and administrative. The decrease in SG&A expense during the year ended December 31, 2018 compared to the year ended December 31, 2017 was primarily due to a $6.9 million decrease in sales and use tax primarily resulting from the settlement of audits in the fourth quarter of 2018, a $3.5 million decrease in bad debt expense, a $1.4 million decrease in facility rent expense and a $1.3 million decrease in corporate office relocation costs (see Note 19 (“Corporate Office Relocation”) to our Financial Statements), partially offset by a $2.9 million increase in professional expenses.

Depreciation and amortization. The decrease in depreciation and amortization expense during the year ended December 31, 2018 compared to the year ended December 31, 2017 was primarily due to a decrease in depreciation expense resulting from certain assets reaching the end of their depreciable lives as well as the impact of asset impairments during 2017 and 2018, partially offset by an increase in depreciation expense associated with fixed asset additions.

Long-lived asset impairment. During the years ended December 31, 2018 and 2017, we reviewed the future deployment of our idle compression assets for units that were not of the type, configuration, condition, make or model that are cost efficient to maintain and operate. In addition, we evaluated for impairment idle units that had been culled from our fleet in prior years and were available for sale. See Note 17 (“Long-Lived Asset Impairment”) to our Financial Statements for further details.

The following table presents the results of our impairment review, as recorded in our contract operations segment (dollars in thousands):
 
Year Ended December 31,
 
2018
 
2017
Idle compressors retired from the active fleet
310

 
325

Horsepower of idle compressors retired from the active fleet
115,000

 
100,000

Impairment recorded on idle compressors retired from the active fleet
$
28,127

 
$
26,287


In addition to the impairment discussed above, $2.9 million of property, plant and equipment was impaired during the year ended December 31, 2017 as the result of physical asset observations and other events that indicated the carrying values of the assets, which were comprised of approximately 7,000 horsepower of idle compressors, were not recoverable and $0.8 million of leasehold improvements and furniture and fixtures that were impaired in connection with the relocation of our corporate office. See Note 19 (“Corporate Office Relocation”) to our Financial Statements for further details.

Restatement and other charges. During the year ended December 31, 2018 we recorded $1.3 million for the expected recovery of shared professional and legal fees incurred related to the restatement of prior period financial statements and disclosures and related matters. We were billed $1.3 million and $4.4 million for our share of these fees during 2018 and 2017, respectively.

Restructuring and other charges. During the year ended December 31, 2017, we incurred $1.4 million, of costs associated with the Spin-off, which were directly attributable to Archrock. No such costs were incurred subsequent to December 31, 2017.


40


Interest expense. The increase in interest expense during the year ended December 31, 2018 compared to the year ended December 31, 2017 was primarily due to increases in the average outstanding balance of long-term debt and the weighted average effective interest rate partially offset by a $0.6 million write-off of deferred financing costs associated with the termination of the Former Credit Facility in 2017.

Debt extinguishment loss. We recorded a debt extinguishment loss of $2.5 million during the year ended December 31, 2018 as a result of the termination of the Archrock Credit Facility. We recorded a debt extinguishment loss of $0.3 million during the year ended December 31, 2017 as a result of the termination of the Former Credit Facility. See Note 13 (“Long-Term Debt”) to our Financial Statements for further details.

Transaction-related costs. We incurred $10.2 million and $0.3 million of costs related to the Merger consisting of financial advisory, legal and other professional fees during the years ended December 31, 2018 and 2017, respectively. See Note 15 (“Equity”) to our Financial Statements for further details of this transaction.

Gain on sale of assets, net. Included in gain on sale, net of assets during the year ended December 31, 2018 compared to the year ended December 31, 2017 was a $1.9 million decrease in gains recognized on land and building sales, offset by a $1.3 million increase in gains recognized on the sale of compression equipment and a $0.5 million decrease in losses recognized on the sale of other assets.

Other income, net. The decrease in other income, net during the year ended December 31, 2018 compared to the year ended December 31, 2017 was primarily due to a $0.6 million increase in indemnification expense incurred pursuant to our tax matters agreement with Exterran Corporation partially offset by a $0.5 million increase in indemnification income earned pursuant to the same agreement and $0.3 million in interest income earned related to a tax refund.

Income Taxes
(dollars in thousands)
 
Year Ended December 31,
 
Increase
 
2018

2017
 
(Decrease)
Provision for (benefit from) income taxes
$
6,150

 
$
(61,083
)
 
(110
)%
Effective tax rate
17
%
 
143
%
 
(126
)%

The change in provision for (benefit from) income taxes during the year ended December 31, 2018 compared to the year ended December 31, 2017 was primarily due to the tax benefit from remeasuring our deferred tax liabilities and assets due to the corporate income tax rate reduction from the TCJA (see Note 20 (“Income Taxes”) to our Financial Statements) recorded in 2017 compared to 2018 and an increase in book income tax effected at the lower corporate income tax rate in 2018 as the result of the TCJA, partially offset by a lower unrecognized tax benefit recorded in 2018 compared to 2017 and benefits recorded in 2018 for the settlement of a tax audit and the release of an unrecognized tax benefit due to the expiration of a statute of limitations.

Net (Income) Loss Attributable to the Noncontrolling Interest
(dollars in thousands)
 
Year Ended December 31,
 
Increase
 
2018
 
2017
 
(Decrease)
Net (income) loss attributable to the noncontrolling interest
$
(8,097
)
 
$
543

 
(1,591
)%

The noncontrolling interest comprises the portion of the Partnership’s earnings that are applicable to the Partnership’s publicly-held common unitholder interest through the completion of the Merger. Immediately prior to the Merger and as of December 31, 2017, public unitholders held an ownership interest in the Partnership of 57%. The change in net (income) loss attributable to the noncontrolling interest was primarily due to the change in net income (loss) of the Partnership partially offset by Archrock’s acquisition of all of the outstanding common units of the Partnership in conjunction with the Merger. The change in net income (loss) of the Partnership was primarily due to the increase in revenue and decreases in SG&A, depreciation and amortization, long-lived asset impairment and provision for income taxes, partially offset by increases in cost of sales (excluding depreciation and amortization), interest expense, net and transaction-related costs.


41


Liquidity and Capital Resources
 
Overview

Our ability to fund operations, finance capital expenditures and pay dividends depends on the levels of our operating cash flows and access to the capital and credit markets. Our primary sources of liquidity are cash flows generated from our operations and our borrowing availability under the Credit Facility. Our cash flow is affected by numerous factors including prices and demand for our services, oil and natural gas exploration and production spending, conditions in the financial markets and other factors. We believe that our operating cash flows and borrowings under the Credit Facility will be sufficient to meet our liquidity needs through at least December 31, 2020.

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.

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; 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 compressors that we add to our fleet. In addition to the cost of newly acquired compressors, growth capital expenditures can also include the upgrading of major components on an existing compression package where the current configuration of the compression package 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 compression package 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 compression package, such as the engine, compressor and cooler, which return the components to a like-new condition, but do not modify the applications for which the compression package was designed.

Growth capital expenditures were $300.5 million, $251.6 million and $172.5 million during the years ended December 31, 2019, 2018 and 2017, respectively. The increase in growth capital expenditures in 2019 compared to 2018 and also in 2018 compared to 2017 was primarily due to increased investment in new compression equipment as a result of increased customer demand to support higher U.S natural gas production levels. We anticipate decreased 2020 growth capital expenditures due to an expected deceleration in the growth rate of natural gas production in 2020 as compared to 2019.

Maintenance capital expenditures were $58.6 million, $49.7 million and $35.7 million during the years ended December 31, 2019, 2018 and 2017, respectively. The increase in maintenance capital expenditures in 2019 compared to 2018 was due to an increase in scheduled maintenance activities in 2019 due to maintenance cycle requirements as well as the increase in horsepower as the result of the Elite Acquisition. The increase in 2018 compared to 2017 was primarily due to the increase in idle horsepower returning to operation and the increase in scheduled maintenance activities in 2018 due to maintenance cycle requirements. We intend to grow our business both organically and through third-party acquisitions. 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 exceed our cost of capital. We currently plan to spend approximately $165 million to $195 million in capital expenditures during 2020, primarily consisting of approximately $80 million to $100 million for growth capital expenditures and approximately $57 million to $63 million for maintenance capital expenditures.


42


Financial Resources

Revolving Credit Facilities

Credit Facility. During the years ended December 31, 2019 and 2018, the Credit Facility had an average daily balance of $855.3 million and $768.5 million, respectively. The weighted average annual interest rate on the outstanding balance under the Credit Facility, excluding the effect of interest rate swaps, was 4.3% and 5.4% at December 31, 2019 and 2018, respectively.

On November 8, 2019, we amended the Credit Facility to, among other things, extend the maturity date of the Credit Facility from March 30, 2022 to November 8, 2024 (or June 3, 2022, if any portion of the 2022 notes remains outstanding at such date) and change the applicable margin for borrowings under the Credit Facility such that (i) the applicable margin for Eurodollar loans, as defined in the Credit Facility agreement, ranges from 2.00% to 2.75% and (ii) the applicable margin for Alternative Base Rate loans ranges from 1.00% to 1.75%, in each case determined based on a total leverage ratio pricing grid.

On February 23, 2018, we amended the Credit Facility to, among other things:

increase the maximum Total Debt to EBITDA ratios, as defined in the Credit Facility agreement (see below for the revised ratios), effective as of the execution of Amendment No. 1 in February 2018; and

effective upon completion of the Merger in April 2018:

*
increase the aggregate revolving commitment from $1.1 billion to $1.25 billion; and

*
increase the amount available for the issuance of letters of credit from $25.0 million to $50.0 million.

See Note 13 (“Long-Term Debt”) to the Financial Statements for further details of these amendments.

Portions of the Credit Facility up to $50.0 million are available for the issuance of swing line loans. Subject to certain conditions, including the approval by the lenders, we are able to increase the aggregate commitments under the Credit Facility by up to an additional $250.0 million. The Credit Facility borrowing base consists of eligible accounts receivable, inventory and compressors.

We must maintain the following consolidated financial ratios, as defined in the Credit Facility agreement:

EBITDA to Interest Expense
2.5 to 1.0
Senior Secured Debt to EBITDA
3.5 to 1.0
Total Debt to EBITDA
 
Through fiscal year 2019
5.75 to 1.0
Through second quarter of 2020
5.50 to 1.0
Thereafter (1)
5.25 to 1.0
——————
(1) 
Subject to a temporary increase to 5.5 to 1.0 for any quarter during which an acquisition satisfying certain thresholds is completed and for the two quarters immediately following such quarter.

As a result of the ratio requirements above, $669.7 million of the $723.3 million of undrawn capacity was available for additional borrowings as of December 31, 2019.

The Credit Facility agreement contains various additional covenants including, but not limited to, mandatory prepayments from the net cash proceeds of certain asset transfers, restrictions on the use of proceeds from borrowings and limitations on our 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 distributions. In addition, if as of any date we have cash and cash equivalents (other than proceeds from a debt or equity issuance received in the 30 days prior to such date reasonably expected to be used to fund an acquisition permitted under the Credit Facility agreement) in excess of $50.0 million, then such excess amount will be used to pay down outstanding borrowings of a corresponding amount under the Credit Facility.

As of December 31, 2019, we were in compliance with all covenants under the Credit Facility.


43


Archrock Credit Facility. In April 2018, in connection with the Merger, we terminated the Archrock Credit Facility and borrowed on the Credit Facility to repay $63.2 million in borrowings and accrued and unpaid interest and fees outstanding. All commitments under the Archrock Credit Facility were terminated and the $15.4 million of letters of credit outstanding under the Archrock Credit Facility were converted to letters of credit under the Credit Facility. Prior to its termination, the Archrock Credit Facility required us to maintain various financial ratios and other covenants, all of which we were in compliance with through its closing. The average daily debt balance under the Archrock Credit Facility in 2018, through its closing in April 2018, was $51.7 million.

Senior Notes Transactions

On December 20, 2019, we completed a private offering of $500.0 million aggregate principal amount of 6.25% senior notes due April 2028 and received net proceeds of $491.8 million after deducting issuance costs. The net proceeds were used to partially repay borrowings outstanding under the Credit Facility.

On March 21, 2019, we completed a private offering of $500.0 million aggregate principal amount of 6.875% senior notes due April 2027 and received net proceeds of $491.2 million after deducting issuance costs. The net proceeds were used to repay borrowings outstanding under the Credit Facility.

On April 5, 2019, we repaid the 2021 Notes with borrowings from our Credit Facility.

See Note 13 (“Long-Term Debt”) to our Financial Statements for further details of these transactions.

2022 Notes

The 2022 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 2022 Notes) and certain of the Partnership’s future subsidiaries. The 2022 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 2022 Notes and guarantees are effectively subordinated to all existing and future indebtedness and other liabilities of any future non-guarantor subsidiaries. Guarantees by the Partnership’s subsidiaries are full and unconditional, subject to customary release provisions, and constitute joint and several obligations. The Partnership has no assets or operations independent of its subsidiaries and there are no significant restrictions upon its subsidiaries’ ability to distribute funds to the Partnership.

Partnership Capital Offering

In August 2017, the Partnership sold, pursuant to a public underwritten offering, 4,600,000 common units, including 600,000 common units pursuant to an over-allotment option. The Partnership received net proceeds of $60.3 million after deducting underwriting discounts, commissions and offering expenses, which it used to repay borrowings outstanding under the Credit Facility. In connection with this sale and as permitted under its partnership agreement, the Partnership sold 93,163 general partner units to its General Partner for a contribution of $1.3 million to maintain the General Partner’s approximate 2% general partner interest in the Partnership.

Cash Flows

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): 
 
Year Ended December 31,
 
2019
 
2018
 
2017
Net cash provided by (used in) operations:
 
 
 
 
 
Operating activities
$
290,147

 
$
225,947

 
$
201,664

Investing activities
(514,560
)
 
(284,923
)
 
(174,487
)
Financing activities
222,488

 
54,050

 
(19,775
)
Net change in cash and cash equivalents
$
(1,925
)
 
$
(4,926
)
 
$
7,402



44


 Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

Operating Activities. The increase in net cash provided by operating activities during the year ended December 31, 2019 compared to the year ended December 31, 2018 was primarily due to an increase in revenue from our contract operations business, the receipt of cash proceeds in 2019 pursuant to a settlement of certain sales and use tax audits and decreases in accounts receivable and cost of sales (excluding depreciation and amortization). These cash inflows were partially offset by increases in cash SG&A expenses and interest paid on our long-term debt and a decrease in accounts payable and other liabilities.

Investing Activities. The increase in net cash used in investing activities during the year ended December 31, 2019 compared to the year ended December 31, 2018 was primarily due to $214.0 million of cash paid in the Elite Acquisition during the year ended December 31, 2019 and a $66.1 million increase in capital expenditures, partially offset by a $47.0 million increase in proceeds from the sale of property, plant and equipment and other assets, including $30.0 million in proceeds from the Harvest Sale.

Financing Activities. The increase in net cash provided by financing activities during the year ended December 31, 2019 compared to the year ended December 31, 2018 was primarily due to a $214.3 million net increase in borrowings of long-term debt and an $11.8 million decrease in distributions paid to noncontrolling partners in the Partnership. These cash flows were partially offset by a $20.2 million increase in dividends paid to Archrock shareholders, a $19.1 million increase in payments for debt issuance costs and an $18.7 million decrease in contributions from Exterran Corporation.