PART I
Item 1. Business.
The financial statements presented in this Annual Report are the consolidated financial statements of TETRA Technologies, Inc., a Delaware corporation and its subsidiaries. When the terms “TETRA,” “the Company,” “we,” “us,” or “our” are used in this document, those terms refer to TETRA Technologies, Inc. and its consolidated subsidiaries.
TETRA is a Delaware corporation, incorporated in 1981. Our corporate headquarters are located at 24955 Interstate 45 North, The Woodlands, Texas, 77380. Our phone number is 281-367-1983, and our website is accessed at www.tetratec.com. Our common stock is traded on the New York Stock Exchange under the symbol “TTI.”
Our Corporate Governance Guidelines, Code of Business Conduct, Code of Ethics for Senior Financial Officers, Audit Committee Charter, Compensation Committee Charter, and Nominating and Corporate Governance Committee Charter, as well as our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, and Current Reports on Form 8-K, and all amendments to those reports are all available, free of charge, on our website at www.tetratec.com as soon as practicable after we file the reports with the SEC. Information contained on or connected to our website is not, and shall not be deemed to be, a part of this Annual Report on Form 10-K or incorporated into any other filings with the SEC. The documents referenced above are available in print at no cost to any stockholder who requests them from our Corporate Secretary.
About TETRA
TETRA Technologies, Inc., together with its consolidated subsidiaries, is a leading,
geographically diversified oil and gas services company, focused on completion fluids and associated products and services, water management, frac flowback, production well testing, offshore rig cooling, and compression services and equipment. Prior to March 2018, our operations also included selected offshore services including well plugging and abandonment, decommissioning, and diving, as well as a limited domestic oil and gas production business.
As of December 31, 2017 we were composed of
five
reporting segments organized into
four
divisions -
Fluids, Production Testing, Compression, and Offshore
.
Our
Fluids Division
manufactures and markets clear brine fluids, additives, and associated products and services to the oil and gas industry for use in well drilling, completion and workover operations in the United States and in certain countries in Latin America, Europe, Asia, the Middle East and Africa. The division also markets liquid and dry calcium chloride products manufactured at its production facilities or purchased from third-party suppliers to a variety of markets outside the energy industry. The Fluids Division also provides domestic onshore oil and gas operators with a wide variety of water management services.
Our
Production Testing Division
provides frac flowback, production well testing, offshore rig cooling, and other associated services and early production facilities (EPFs) in many of the major oil and gas producing regions in the United States, Mexico, and Canada, as well as in oil and gas basins in certain regions in South America, Africa, Europe, the Middle East and Australia.
Our
Compression Division
is a provider of compression services and equipment for natural gas and oil production, gathering, transportation, processing, and storage. The Compression Division's equipment sales business includes the fabrication and sale of standard compressor packages, custom-designed compressor packages and oilfield pump systems designed and fabricated at the division's facilities. The Compression Division's aftermarket business provides compressor package reconfiguration and maintenance services and compressor package parts and components manufactured by third-party suppliers. The Compression Division provides its services and equipment to a broad base of natural gas and oil exploration and production, midstream, transmission, and storage companies operating throughout many of the onshore producing regions of the United States, as well as in a number of foreign countries, including Mexico, Canada and Argentina.
Our
Offshore Division
consists of
two
operating segments, both of which were disposed on March 1, 2018: Offshore Services and Maritech. The Offshore Services segment provided services primarily to the offshore oil and gas industry, consisting of: (1) downhole and subsea services, such as well plugging and abandonment and
inspection, repair and maintenance services; (2) decommissioning and certain construction services utilizing heavy lift barges and various cutting technologies with regard to offshore oil and gas production platforms and pipelines; and (3) conventional and saturation diving services.
For additional information regarding the sale of the Offshore Division, see "Note C - Acquisitions and Dispositions" of the Notes to Consolidated Financial Statements.
The
Maritech
segment was a limited oil and gas production operation. During 2011 and the first quarter of 2012, Maritech sold substantially all of its oil- and gas-producing property interests. Maritech’s operations consisted primarily of the ongoing abandonment and decommissioning associated with its remaining offshore wells and production platforms.
We continue to pursue a long-term growth strategy that includes expanding our continuing core businesses, which excludes our recently disposed Offshore Services and Maritech segments, through internal growth and acquisitions, domestically and internationally. For financial information for each of our segments, including information regarding revenues and total assets, see “
Note Q
- Industry Segments and Geographic Information” contained in the Notes to Consolidated Financial Statements.
Products and Services
Fluids Division
Liquid calcium chloride, calcium bromide, zinc bromide, zinc calcium bromide, sodium bromide, and blends of such products manufactured by our Fluids Division are referred to as clear brine fluids ("CBFs") in the oil and gas industry. CBFs are salt solutions that have variable densities and are used to control bottom-hole pressures during oil and gas completion and workover operations. The Fluids Division sells CBFs and various CBF additives to U.S. and foreign oil and gas exploration and production companies and to other companies that service customers in the oil and gas industry.
The Fluids Division provides both stock and custom-blended CBFs based on each customer's specific needs and the proposed application. The Fluids Division provides a broad range of associated CBF services, including: on-site fluids filtration, handling and recycling; wellbore cleanup; fluid engineering consultation; and fluid management services. The Fluids Division's newest CBF technology, TETRA CS Neptune
®
completion fluids, are high-density, solids-, zinc- and formate-free completion fluids. They were developed by TETRA to be environmentally friendly and cost-effective alternatives to traditional zinc bromide and cesium formate high-density completion fluids for use in well completion and workover operations, as well as a low-solids reservoir drilling fluid.
We offer to repurchase (buyback) certain used CBFs from customers, which we are able to recondition and recycle. Selling used CBFs back to us reduces the net cost of the CBFs to our customers and minimizes our customers’ need to dispose of used fluids. We recondition used CBFs through filtration, blending and the use of proprietary chemical processes, and then market the reconditioned CBFs.
By blending different stock CBFs and using various additives, we are able to modify the specific density, crystallization temperature, and chemical composition of the CBFs as necessary. The division’s fluid engineering personnel determine the optimal CBF blend for a customer’s particular application to maximize its effectiveness and lifespan. Our filtration services use a variety of techniques and equipment to remove particulates from CBFs at the customer’s site so that the CBFs can be reused. Filtration also enables recovery of a greater percentage of used CBFs for reconditioning.
The Fluids Division also provides a wide variety of water management services that support hydraulic fracturing in unconventional well completions for domestic onshore oil and gas operators. These services include fresh and produced water analysis, treatment, storage, transfer, engineering, recycling, and environmental risk mitigation. The Fluids Division's patented equipment and processes include BioRid® treatment services, certain blending technologies, and TETRA STEEL
TM
1200 rapid deployment water transfer system. The Fluids Division seeks to design environmentally friendly solutions for the unique needs of each customer’s wellsite in order to maximize operational performance, and efficiency and minimize the use of fresh water. These include tailored “Last Mile” infrastructure - which consists of water storage ponds, movable storage tanks, a network of water transfer lines including TETRA STEEL™ lay-flat hose, TETRA Blend™ automated transfer and blending of produced water, and oil recovery from produced water via the TETRA Orapt™ mobile oil separator system - to transfer water around the well pads in a safe, efficient and environmentally responsible manner
.
On February 28, 2018, pursuant to a purchase agreement dated February 13, 2018 (the 'SwiftWater Purchase Agreement"), we purchased all of the equity interests in SwiftWater Energy Services, LLC ("SwiftWater"), which is engaged in the business of providing water management and water solutions to oil and gas operators in the Permian Basin market of Texas. SwiftWater provides a diverse range of water management equipment and services for operators in the Permian Basin, offering an integrated line of services ranging from lay-flat hose water transfer, water treatment, above-ground water storage for fresh and produced water applications, secondary frac tank containment, poly pipe, pit lining rentals, and supporting ancillary equipment. For additional information regarding the acquisition of SwiftWater, see "Note C - Acquisitions and Dispositions" of the Notes to Consolidated Financial Statements.
The Fluids Division manufactures liquid and dry calcium chloride and liquid calcium bromide, zinc bromide, zinc calcium bromide, and sodium bromide for distribution, primarily into energy markets. Liquid and dry calcium chloride are also sold into water treatment, industrial, cement, food processing, road maintenance, ice melt, agricultural, and consumer products markets. Sodium bromide is also sold into industrial water treatment markets, where it is used as a biocide in recirculated cooling tower waters and in other applications.
Our calcium chloride manufacturing facilities are located in the United States and Finland. We also acquire calcium chloride inventory from other producers. In the United States, we manufacture calcium chloride at five manufacturing plant facilities, the largest of which is our plant near El Dorado, Arkansas, which produces liquid and flake calcium chloride products and sodium chloride. Liquid and flake calcium chloride are also produced at our Kokkola, Finland, plant. We operate our European calcium chloride operations under the name TETRA Chemicals Europe. We also manufacture liquid calcium chloride at our facilities in Parkersburg, West Virginia and Lake Charles, Louisiana, and we have two solar evaporation facility locations located in San Bernardino County, California, that produce liquid calcium chloride and sodium chloride from underground brine reserves, which are naturally replenished. All of our calcium chloride production facilities have a combined production capacity of more than 1.5 million equivalent liquid tons per year.
Our Fluids Division manufactures liquid calcium bromide, zinc bromide, zinc calcium bromide and sodium bromide at our West Memphis, Arkansas facility. A patented and proprietary process utilized at this facility uses bromine and zinc to manufacture zinc bromide. This facility also uses proprietary processes to manufacture calcium bromide and sodium bromide and to recondition and upgrade used CBFs that we have repurchased from our customers.
See “
Note Q
- Industry Segments and Geographic Information” in the Notes to Consolidated Financial Statements for financial information about the Fluids Division.
Production Testing Division
Our Production Testing Division provides frac flowback services, early production facilities and services, production well testing services, offshore rig cooling services, and other associated services, including well flow management and evaluation services that enable operators to quantify oil and gas reserves, optimize oil and gas production and minimize oil and gas reservoir damage. In certain gas-producing basins, water, sand and other abrasive materials commonly accompany the initial production of natural gas, often under high-pressure and high-temperature conditions and, in some cases, from reservoirs containing high levels of hydrogen sulfide gas. The Production Testing Division provides the specialized equipment and qualified personnel to address these impediments to production. Early production services typically include sophisticated evaluation techniques for reservoir management, including unconventional shale reservoir exploitation and optimization of well workover programs. Frac flowback and production well testing services may include well control, well cleanup and laboratory analysis. These services are utilized in the completion process after hydraulic fracturing and in the production phase of oil and gas wells.
Our Production Testing Division maintains one of the largest fleets of high-pressure production testing equipment in the United States, including equipment designed to work in environments where high levels of hydrogen sulfide gas are present. The division has domestic operating locations in Colorado, Louisiana, North Dakota, Oklahoma, Pennsylvania, Texas, West Virginia, and Wyoming. The division also has locations in Canada, and in certain countries in South America, Europe, Africa, and the Middle East. Production Testing operations in Canada are provided through our subsidiary, Greywolf Energy Services ("Greywolf").
Through our Optima Solutions Holdings Limited subsidiary ("OPTIMA"), the Production Testing Division is a provider of offshore oil and gas rig cooling services and associated products that suppress heat generated by high rate flaring of hydrocarbons during offshore oil and gas well test operations.
See “
Note Q
- Industry Segments and Geographic Information” in the Notes to Consolidated Financial Statements for financial information about the Production Testing Division.
Compression Division
Our Compression Division is a provider of compression services and equipment for natural gas and oil production, gathering, transportation, processing, and storage. The Compression Division fabricates and sells standard and custom-designed compressor packages, as well as oilfield fluid pump systems, and provides aftermarket services and compressor package parts and components manufactured by third-party suppliers. The majority of the Compression Division’s service compression fleet is monitored 24/7 via satellite telemetry from Fleet Reliability Centers (FRC) located at The Woodlands, Texas-based corporate office and the Midland, Texas-based packaging facility. The Compression Division provides its compression services and equipment to a broad base of natural gas and oil exploration and production, midstream, transmission and storage companies operating throughout many of the onshore producing regions of the United States, Canada and Mexico, as well as certain countries in South America.
The Compression Division is one of the largest providers of natural gas compression services in the United States. The compression and related services business includes a service fleet of approximately 5,800 compressor packages providing approximately 1.1 million in aggregate horsepower, utilizing a full spectrum of low-, medium-, and high-horsepower engines. Low-horsepower compressor packages enhance production for dry gas wells and liquid-loaded gas wells by deliquifying wells, lowering wellhead pressure, and increasing gas velocity. Our low-horsepower compressor packages are also utilized in connection with oil and liquids production and in vapor recovery and casing gas system applications. Low- to medium-horsepower compressor packages are typically utilized in wellhead, gathering, and other applications primarily in connection with oil and liquids production. Our high-horsepower compressor package offerings are typically utilized for natural gas production, natural gas gathering, centralized compression facilities and midstream applications.
The horsepower of our compression services fleet on
December 31, 2017
, is summarized in the following table:
|
|
|
|
|
|
|
|
|
Range of Horsepower Per Package
|
|
Number of Packages
|
|
Aggregate Horsepower
|
|
% of Total Aggregate Horsepower
|
|
|
|
|
|
|
|
0 - 100
|
|
3,842
|
|
180,156
|
|
16.7
|
%
|
101 - 800
|
|
1,590
|
|
444,520
|
|
41.1
|
%
|
Over 800
|
|
341
|
|
457,243
|
|
42.3
|
%
|
Total
|
|
5,773
|
|
1,081,919
|
|
100.0
|
%
|
Our Compression Division's equipment sales business includes the fabrication and sale of standard compressor packages, custom-designed compressor packages and oilfield fluid pump systems that are designed and fabricated primarily at its facility in Midland, Texas. Our compressor packages are typically sold to natural gas and oil exploration and production, mid-stream, transmission, and storage companies for use in various applications including gas gathering, gas lift, carbon dioxide injection, wellhead compression, gas storage, refrigeration plant, gas processing, pressure maintenance, pipeline, vapor recovery, gas transmission, fuel gas booster, and coal bed methane systems. We design and fabricate natural gas reciprocating and rotary compressor packages up to 8,000 horsepower for use in our service fleet and for sale to our broadened customer base. Our pump systems can be utilized in numerous applications including oil production, transfer and pipelines, as well as water injection and disposal.
The Compression Division's aftermarket business provides a wide range of services and compressor package parts and components manufactured by third-party suppliers to support the needs of customers who own compression equipment. These services include operations, maintenance, overhaul and reconfiguration services, which may be provided under turnkey engineering, procurement and construction contracts. This business employs
factory trained sales and support personnel in most of the major oil- and natural gas-producing basins in the United States to perform these services.
Virtually all of our Compression Division's operations are conducted through our partially owned subsidiary, CSI Compressco LP ("CCLP"). Through our wholly owned subsidiary, CSI Compressco GP Inc., we manage and control CCLP, and accordingly, we consolidate CCLP results of operation in our consolidated results of operation. As of
December 31, 2017
, common units held by the public represented approximately a
60%
common unit ownership interest in CCLP.
See “
Note Q
- Industry Segments and Geographic Information” in the Notes to Consolidated Financial Statements for financial information about the Compression Division.
Offshore Division
Our Offshore Division consists of two operating segments: Offshore Services and Maritech. On March 1, 2018, we closed a series of related transactions that resulted in the disposition of these two businesses. Pursuant to an Asset Purchase and Sale Agreement (the "Maritech Asset Purchase Agreement") with Orinoco Natural Resources, LLC ("Orinoco") Orinoco purchased certain offshore oil, gas and mineral leases and related assets of Maritech (the "Maritech Properties"). Immediately thereafter, we closed a Membership Interest Purchase and Sale Agreement (the "Maritech Equity Purchase Agreement") with Orinoco, whereby Orinoco purchased all of the equity interests of Maritech (the "Maritech Equity Interests"). Immediately thereafter, we closed an Equity Interest Purchase Agreement (the "Offshore Services Purchase Agreement") with Epic Offshore Specialty, LLC, an affiliate of Orinoco ("Epic Offshore"), whereby Epic Offshore purchased (the "Offshore Services Sale") all of the equity in TSB Offshore, Inc. and TETRA Applied Technologies, LLC, which owns all of the equity interests in Epic Diving & Marine Services, LLC, which are the wholly owned subsidiaries that comprise our Offshore Services segment operations (the "Offshore Services Equity Interests").
Under the terms of the Maritech Asset Purchase Agreement, the Maritech Equity Purchase Agreement, and the Offshore Services Purchase Agreement, the consideration delivered by Orinoco and Epic Offshore for the Maritech Properties, the Maritech Equity Interests and the Offshore Services Equity Interests consisted of (i) the assumption by Orinoco of all of the liabilities and obligations relating to the ownership, operation and condition of the Maritech Properties and the provision of certain indemnities by Orinoco to us under the Maritech Asset Purchase Agreement, (ii) the assumption by Orinoco of all of the liabilities of Maritech and the provision of certain indemnities by Orinoco under the Maritech Equity Purchase Agreement, (iii) the assumption by Epic Offshore of substantially all of the liabilities of the Offshore Services Equity Interests relating to the periods following the closing of the Offshore Services Sale and the provision of certain indemnities by Epic Offshore under the Offshore Services Purchase Agreement, (iv) cash in the amount $3.1 million which is equal to the value of the fuel in the vessels owned by Offshore Services as of the closing plus the value (determined to be sixty percent of the amount paid by Offshore Services therefore) of all usable spare parts and supply inventory of Offshore Services, (v) a promissory note in the original principal amount of $7.5 million payable by Epic Offshore to us in full, together with interest at a rate of 1.52% per annum, on December 31, 2019, (vi) performance by Orinoco under a Bonding Agreement executed in connection with the Maritech Asset Purchase Agreement and the Maritech Equity Purchase Agreement whereby Orinoco provided at closing non-revocable performance bonds in an amount equal to $46.8 million to cover the performance by Orinoco and Maritech of the asset retirement obligations of Maritech, to be replaced within 90 days of the closing with non-revocable performance bonds, meeting certain requirements, in the sum of $47.0 million, and (vii) the delivery of a personal guaranty agreement from Thomas M. Clarke and Ana M. Clarke guaranteeing the payment obligations of Orinoco under the Bonding Agreement (collectively, the "Transaction Consideration"). See "Note C - Acquisitions and Dispositions" in the Notes to Consolidated Financial Statements for financial information about the February 2018 sale of the Offshore Division.
As a result of these transactions, we have effectively exited the businesses of our Offshore Services and Maritech segments.
Offshore Services Segment.
The Offshore Services segment provided: (1) downhole and subsea services, such as well plugging and abandonment and inspection, repair and maintenance services; (2) decommissioning and certain construction services utilizing heavy lift barges and various cutting technologies with regard to offshore oil and gas production platforms and pipelines; and (3) conventional and saturation diving services. We provided these services to offshore oil and gas operators, primarily in the U.S. Gulf of Mexico. We offered comprehensive integrated services, including individualized engineering consultation and project management services.
Maritech Segment.
The Maritech segment was a limited oil and gas production operation in the offshore U.S. Gulf of Mexico. During 2011 and the first quarter of 2012, Maritech sold substantially all of its proved reserves. Subsequent to these sales of proved reserves, Maritech’s remaining operations consisted primarily of the ongoing abandonment and decommissioning of its remaining offshore wells, facilities and production platforms. As part of the sale of our Offshore Division in March 2018, Orinoco purchased Maritech and its remaining oil and gas leases and assumed all of Maritech's abandonment and decommissioning obligations.
The sales of substantially all of Maritech’s oil and gas producing properties during 2011 and 2012 essentially removed us from the oil and gas exploration and production business, and significantly all of Maritech’s oil and gas acquisition, development and exploitation activities ceased. Since the sales of its proved reserves, Maritech’s remaining oil and gas reserves and production were negligible. Prior to March 1, 2018, Maritech’s operations consisted primarily of the well abandonment and decommissioning of its remaining offshore oil and gas platforms and facilities. During the three year period ended
December 31, 2017
, Maritech spent approximately
$14.9 million
on such efforts. Approximately
$46.7 million
of Maritech decommissioning liabilities remained as of
December 31, 2017
, and such liabilities were assumed by Orinoco as part of the sale of the Offshore Division.
Maritech’s decommissioning liabilities are established based on what it estimates a third party would charge to plug and abandon the wells, decommission the pipelines and platforms, and clear the sites associated with its properties. For a further discussion of Maritech’s historical adjustments to its decommissioning liabilities, see “
Note I
- Decommissioning and Other Asset Retirement Obligations” in the Notes to Consolidated Financial Statements.
See “
Note Q
- Industry Segments and Geographic Information” in the Notes to Consolidated Financial Statements for financial information about the Offshore Division.
Sources of Raw Materials
Our Fluids Division manufactures calcium chloride, calcium bromide, zinc bromide, zinc calcium bromide, and sodium bromide for sale to its customers. The Fluids Division also recycles used calcium bromide and zinc bromide CBFs repurchased from its oil and gas customers.
The Fluids Division manufactures liquid calcium chloride, either from underground brine or by reacting hydrochloric acid with limestone. The Fluids Division also purchases liquid and dry calcium chloride from a number of U.S. and foreign chemical manufacturers. Our El Dorado, Arkansas, plant produces liquid and flake calcium chloride and sodium chloride, utilizing underground brine (tail brine) obtained from Lanxess AG ("Lanxess," which acquired Chemtura Corporation during 2017) that contains calcium chloride and sodium chloride. We also produce calcium chloride and sodium chloride at our two facility locations in San Bernardino County, California, by solar evaporation of pumped underground brine reserves that contain calcium chloride. The underground reserves of this brine are deemed adequate to supply our foreseeable need for calcium chloride at those plants.
The Fluids Division's primary sources of hydrochloric acid are co-product streams obtained from chemical manufacturers. Substantial quantities of limestone are also consumed when converting hydrochloric acid into calcium chloride. Currently, hydrochloric acid and limestone are generally available from multiple sources.
To produce calcium bromide, zinc bromide, zinc calcium bromide, and sodium bromide at our West Memphis, Arkansas, facility, we use bromine, hydrobromic acid, zinc and lime as raw materials. There are multiple sources of zinc that we can use in the production of zinc bromide and zinc calcium bromide. We have a long-term supply agreement with Lanxess, under which the Fluids Division purchases its requirements of raw material bromine from Lanxess’s Arkansas bromine facilities. In addition, we have a long-term agreement with Lanxess under which Lanxess supplies the Fluids’ El Dorado, Arkansas, calcium chloride plant with raw material tail brine from its Arkansas bromine production facilities.
We also own a calcium bromide manufacturing plant near Magnolia, Arkansas, which was constructed in 1985. This plant was acquired in 1988 and is not operable. We currently lease approximately 30,000 gross acres of bromine-containing brine reserves in the vicinity of this plant. While this plant is designed to produce calcium bromide, it could be modified to produce elemental bromine or select bromine compounds. Development of the brine field, construction of necessary pipelines and reconfiguration of the plant would require a substantial capital investment. The long-term Lanxess bromine supply agreement discussed above provides us with a secure supply
of bromine to support the division’s current operations. We do, however, continue to evaluate our strategy related to the Magnolia, Arkansas, assets and their future development. Lanxess has certain rights to participate in future development of the Magnolia, Arkansas assets.
The Fluids and Production Testing Divisions purchase their water management, production testing, and rig cooling equipment and components from third-party manufacturers. CCLP designs and fabricates its reciprocating and rotary screw compressor packages and pumps with components obtained from third party suppliers. These components represent a significant portion of the cost of the compressor packages and pump systems. Some of the components used in the assembly of compressor packages, well monitoring, sand separation, production testing, and rig cooling equipment are obtained from a single supplier or a limited group of suppliers. We do not have long-term contracts with these suppliers or manufacturers. Should we experience unavailability of the components we use to assemble our equipment, we believe there are adequate alternative suppliers and any impact to us would not be severe. CCLP occasionally experiences long-lead times for components from suppliers and, therefore, may at times make purchases in anticipation of future orders.
Market Overview and Competition
Our operations are significantly dependent upon the demand for, and production of, natural gas and oil in the various domestic and international locations in which we operate. Beginning in 2014, and continuing throughout most of 2016, reduced prices of natural gas and oil led to declines in our customers' drilling activities and capital expenditure levels in the domestic and international markets in which we operate. The decline in activity in the natural gas and oil exploration and production industry resulted in reduced demand for certain of our products and services compared to early 2014 levels. With the increase in oil and gas pricing that continued throughout most of 2017 and early 2018, we are seeing indicators of improving demand in the North America and international markets, while offshore activity remains flat year-over-year.
Fluids Division
Our Fluids Division provides its products and services to oil and gas exploration and production companies in the United States and certain foreign markets, and to other customers that service such companies. Current areas of market presence include the onshore U.S., the U.S. Gulf of Mexico, the North Sea, Mexico, and certain countries in South America, Europe, Asia, the Middle East and Africa. Customers with deepwater operations frequently utilize high volumes of CBFs, which can be subject to harsh downhole conditions, such as high pressure and high temperatures. Demand for CBF products offshore is generally driven by completion activity.
Since 2014, there has been increased industry demand for onshore water management services in unconventional shale gas and oil reservoirs in connection with hydraulic fracturing operations. However, beginning in 2015, demand for certain Fluids Division products and services, particularly water management services, was adversely affected by declining oil and natural gas pricing and customer budgetary constraints. Throughout 2017, demand for our North American onshore water management services increased as oil and natural gas prices rose. The Fluids Division provides water management services to a wide-range of onshore oil and gas operators located in all active North America unconventional oil and gas basins. The acquisition of SwiftWater expands our market share in the Permian Basin, which is one of the fastest growing basins for oilfield services globally, by adding significant capacity as well as incremental products and services, with nominal customer overlap.
Our Fluids Division’s principal competitors in the sale of CBFs to the oil and gas industry are Baker Hughes, Baroid, a subsidiary of Halliburton, and M-I Swaco, a subsidiary of Schlumberger. This market is highly competitive, and competition is based primarily on service, availability, and price. Major customers of the Fluids Division include Anadarko, Chesapeake, Chevron, ConocoPhillips, Devon Energy, Encana, EOG Resources, ExxonMobil, Halliburton, LLOG Exploration, Oklahoma Energy Corp., Petrobras, Pioneer Natural Resources, Saudi Aramco, Schlumberger, Shell, Southwestern Energy, Total, Tullow, W & T Offshore, and YPF. The Fluids Division also sells its CBF products through various distributors. Competitors for the division’s water management services include large, multinational providers as well as small, privately owned operators.
Our liquid and dry calcium chloride products have a wide range of uses outside the energy industry. Non-energy market segments where these products are used include water treatment, industrial, food processing, road maintenance, ice melt, agricultural, and consumer products. We also sell sodium bromide into industrial water treatment markets as a biocide under the BioRid
®
tradename. Most of these markets are highly competitive. The Fluids Division’s European calcium chloride operations market our calcium chloride products to certain European
markets. Our principal competitors in the non-energy related calcium chloride markets include Occidental Chemical Corporation and Vitro in North America and NedMag in Europe.
Production Testing Division
Our Production Testing Division provides frac flowback services, early production facilities and services, production well testing services, offshore rig cooling services, and other associated services in various onshore domestic and international locations. The Production Testing Division serves all active North America unconventional oil and gas basins. Through Greywolf, the division serves the western Canada market. In addition, through our OPTIMA subsidiary, the Production Testing Division offers offshore oil and gas rig cooling services and associated products that suppress heat generated by high-rate flaring of hydrocarbons during offshore well testing operations. OPTIMA primarily serves markets in the North Sea, Asia-Pacific, the Middle East and South America.
The U.S. and Canadian production testing markets are highly competitive, and competition is based on availability of appropriate equipment and qualified personnel, as well as price, quality of service, and safety record. We believe that our skilled personnel, operating procedures and safety record give us a competitive advantage. Competition in onshore U.S. and Canadian production testing markets is primarily dominated by numerous small, privately owned operators. Expro International, Halliburton, and Schlumberger, are major competitors in the foreign markets we serve although, we provide these services to their customers on a subcontract basis from time to time. The major customers for this division include Chevron, ConocoPhillips, Eclipse Resources, Encana, EP Energy, EQT, Expro, Peyto, Pioneer Natural Resources, Range Resources, Rice Energy, Saudi Aramco, Schlumberger, Shell, and Vantage Energy.
Compression Division
The Compression Division provides its products and services to a broad base of natural gas and oil exploration and production, midstream, pipeline transmission, and storage companies, operating throughout many of the onshore producing regions of the United States. The Compression Division also has operations in Latin America and other foreign regions. While most of the Compression Division's services are performed throughout Texas, the San Juan Basin, the Rocky Mountain region and the Midcontinent region of the United States, we also have a presence in other U.S. producing regions. The Compression Division continues to seek opportunities to further expand its operations into other regions in the U.S. and elsewhere in the world.
This division’s strategy is to compete on the basis of superior services at a competitive price. The Compression Division believes that it is competitive because of the significant increases in the value that results from the use of its services, its superior customer service, its highly trained field personnel and the quality of the compressor packages it uses to provide services. The Compression Division’s major customers include Anadarko, Cimarex Energy, ConocoPhillips, Denbury Onshore, and Targa Resources.
The compression services and compressor package fabrication business is highly competitive. Certain of the Compression Division's competitors may be able to more quickly adapt to changes within the compression industry and changes in economic conditions as a whole, more readily take advantage of available opportunities and adopt more aggressive pricing policies. Primary competition for our low-horsepower compression services business comes from various local and regional companies that utilize packages consisting of a screw compressor with a separate engine driver or a reciprocating compressor with a separate engine driver. These local and regional competitors tend to compete with us on the basis of price as opposed to our focus on providing production enhancement value to the customer. Competition for the mid- and high-horsepower compression services business comes primarily from large national and multinational companies that may have greater financial resources than ours. Such competitors include ArchRock, AXIP Energy Services, CDM Resource Management, Exterran, J-W Power, and USA Compression. Our competition in the standard compressor package fabrication and sales market includes several large companies and a large number of small, regional fabricators, including some of those who we compete with for compression services, as well as AG Equipment Company, Enerflex, SEC Energy Products & Services, and others. The Compression Division's competition in the custom-designed compressor package market usually consists of larger companies that have the ability to address integrated projects and provide product support after the sale. The ability to fabricate these large custom-designed packages at the Compression Division's facilities, which is near the point of end-use of many customers, is often a competitive advantage.
Offshore Division
Offshore Services Segment
. Demand for the Offshore Services segment’s offshore well abandonment and decommissioning services in the Gulf of Mexico is primarily driven by the maturity and decline of producing fields, aging offshore platform infrastructure, damage to platforms and pipelines from hurricanes and other windstorms, and government regulations, among other factors. Demand for the Offshore Services segment’s construction and other services is driven by the general level of offshore activity of its customers, which is affected by oil and natural gas prices and government regulation. Offshore activities in the Gulf of Mexico are seasonal, with the majority of work occurring during the months of April through October when weather conditions are most favorable. Critical factors required to compete in this market include, among other factors: (i) the proper equipment, including vessels and heavy lift barges; (ii) qualified, experienced personnel; (iii) technical expertise to address varying downhole, surface and subsea conditions, particularly those related to damaged wells and platforms; and (iv) a comprehensive health, safety and environmental program. Our Offshore Services segment's fleet of owned equipment includes two heavy lift derrick barges, the TETRA Hedron, which has a 1,600-metric-ton lift capacity, fully revolving crane and the TETRA Arapaho, which has a 725-metric-ton lift capacity. We believe that the integrated services that we offer and our vessel and equipment fleets satisfy current market requirements in the Gulf of Mexico and allow us to successfully compete in that market.
The Offshore Services segment markets its services primarily to major oil and gas companies and independent operators. One of the Offshore Services segment’s most significant customers historically has been Maritech; however, the amount of work performed for Maritech has been reduced in recent years and the amount of work to be performed in the future for Maritech is expected to continue to decline. Major customers include, Fieldwood Energy, Shell, Stone Energy, Talos Energy, and W&T Offshore. The Offshore Services segment’s services are performed primarily in the U.S. Gulf of Mexico, however, the segment has provided services in the Mexican Gulf of Mexico and in the Asia-Pacific region and is seeking to expand its operations to international markets. Our principal competitors in the U.S. Gulf of Mexico market are Chet Morrison Contractors, Manson Gulf, Montco Oilfield Contractors, Oceaneering, Ranger Offshore, and Superior Energy Services, Inc. This market is highly competitive, and competition is based primarily on service, equipment availability, safety record, and price.
No single customer provided 10% or more of our total consolidated revenues during the year ended
December 31, 2017
.
Other Business Matters
Backlog
The Compression Division’s equipment sales business consist of the fabrication and sale of standard compressor packages, custom-designed compressor packages, and oilfield fluid pump systems that are fabricated to customer specifications and standard specifications, as applicable. The Division's custom-designed compressor packages are typically greater in size and complexity than standard fabrication packages, requiring more labor, materials, and overhead resources. This business requires diligent planning of those resources and project and backlog management in order to meet the customers' desired delivery dates and performance criteria, and achieve fabrication efficiencies. As of
December 31, 2017
, the Compression Division's equipment sales backlog was
$47.5 million
, all of which is expected to be recognized in
2018
, based on title passing to the customer, the customer assuming the risks of ownership, reasonable assurance of collectability, and delivery occurring as directed by our customer. This backlog consists of firm customer orders for which a purchase or work order has been received, satisfactory credit or financing arrangements exist, and delivery has been scheduled. This backlog is a measure of marketing effectiveness that allows us to plan future labor and raw material needs and to measure our success in winning bids from our customers. F
ollowing a record single
$66.7 million
sales order received from a customer in early 2018, the Compression Division's equipment sales backlog has further increased significantly after
December 31, 2017
.
Other than these Compression Division operations, our products and services generally are either not sold under long-term contracts or do not require long lead times to procure or deliver.
Employees
As of
December 31, 2017
, we had approximately 2,600 employees. None of our U.S. employees are presently covered by a collective bargaining agreement. Our foreign employees are generally members of labor
unions and associations in the countries in which they are employed. We believe that our relations with our employees are good.
Patents, Proprietary Technology and Trademarks
As of
December 31, 2017
, we owned or licensed fifty-six (56) issued U.S. patents and had seven (7) patent applications pending in the United States. Twenty five (25) of the U.S. patents and the seven (7) patent applications pending in the U.S. are held by our Offshore Services segment, which was disposed in March 2018. We also had forty-five (45) owned or licensed patents and seven (7) patent applications pending in various other countries. Eight (8) of the foreign patents and one of the foreign patent applications are held by our Offshore Services segment. The foreign patents and patent applications are primarily foreign counterparts to certain of our U.S. patents or patent applications. The issued patents expire at various times through 2035. We have elected to maintain certain other internally developed technologies, know-how, and inventions as trade secrets. While we believe that our patents and trade secrets are important to our competitive positions in our businesses, we do not believe any one patent or trade secret is essential to our success.
It is our practice to enter into confidentiality agreements with key employees, consultants and third parties to whom we disclose our confidential and proprietary information, and we have typical policies and procedures designed to maintain the confidentiality of such information. There can be no assurance, however, that these measures will prevent the unauthorized disclosure or use of our trade secrets and expertise, or that others may not independently develop similar trade secrets or expertise.
We sell various products and services under a variety of trademarks and service marks, some of which are registered in the United States or other countries.
Health, Safety, and Environmental Affairs Regulations
We believe that our service and sales operations and manufacturing plants are in substantial compliance with all applicable U.S. and foreign health, safety, and environmental laws and regulations. We are committed to conducting all of our operations under the highest standards of safety and respect for the environment. However, risks of substantial costs and liabilities are inherent in certain of our operations and in the development and handling of certain products and equipment produced or used at our plants, well locations, and worksites. Because of these risks, there can be no assurance that significant costs and liabilities will not be incurred in the future. Changes in environmental and health and safety regulations could subject us to more rigorous standards. We cannot predict the extent to which our operations may be affected by future regulatory and enforcement policies.
We are subject to various federal, state, local, and foreign laws and regulations relating to health, safety, and the environment, including regulations regarding air emissions, wastewater and storm water discharges, and the disposal of certain hazardous and nonhazardous wastes. Compliance with 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 or associated permits may result in the assessment of fines and penalties and the imposition of other obligations.
Our operations in the United States are subject to various evolving environmental laws and regulations that are enforced by the U.S. Environmental Protection Agency ("EPA"); the Bureau of Safety and Environmental Enforcement ("BSEE") of the U.S. Department of the Interior; the U.S. Coast Guard; and various other federal, state, and local environmental authorities. Similar laws and regulations, designed to protect the health and safety of our employees and visitors to our facilities, are enforced by the U.S. Occupational Safety and Health Administration, and other state and local agencies and authorities. Specific environmental laws and regulations applicable to our operations include: (i) the Federal Water Pollution Control Act of 1972; (ii) the Resource Conservation and Recovery Act of 1976; (iii) the Clean Air Act of 1977; (iv) the Comprehensive Environmental Response, Compensation and Liability Act of 1980 ("CERCLA"); (v) the Superfund Amendments and Reauthorization Act of 1986; (vi) the Federal Insecticide, Fungicide, and Rodenticide Act of 1947; (vii) the Toxic Substances Control Act of 1976; (viii) the Hazardous Materials Transportation Act of 1975; (ix) and the Pollution Prevention Act of 1990. Our operations outside the United States are subject to various foreign governmental laws and regulations relating to the environment, health and safety, and other regulated activities in the countries in which we operate.
We routinely deal with natural gas, oil, and other petroleum products. Hydrocarbons or other hazardous wastes may have been released during our operations or by third parties on wellhead sites where we provide
services or store our equipment or on or under other locations where wastes have been taken for disposal. These properties may be subject to investigatory, remediation, and monitoring requirements under foreign, federal, state, and local environmental laws and regulations.
The U.S. Environmental Protection Agency (the “EPA”) has adopted regulations under the Clean Air Act to control emissions of hazardous air pollutants from reciprocal internal combustion engines and more recently the EPA adopted regulations that establish air emission controls for natural gas and natural gas liquids production, processing and transportation activities, including New Source Performance Standards as well as emission standards to address hazardous air pollutants. Certain CSI compressors are subject to these new requirements and additional control equipment and maintenance operations are required. While we do not believe that compliance with current regulatory requirements will have a material adverse effect on the business, additional regulations could impose new air permitting or pollution control requirements on our equipment that could require us to incur material costs.
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 adversely affect oil and natural gas exploration and production, which in turn could have an adverse effect on us.
We maintain various types of insurance intended to reimburse us for certain costs in the event of an accident, including an explosion or similar event involving our offshore operations. Our insurance program is reviewed not less than annually with our insurance brokers and underwriters. As part of our insurance program for offshore operations, we maintain Commercial General Liability, Protection and Indemnity, and Excess Liability policies that provide third-party liability coverage, including but not limited to death and personal injury, collision, damage to property including fixed and floating objects, pollution, and wreck removal up to the applicable policy limits. Additionally, related to our Offshore Services operations which we disposed in March 2018, we maintained a vessel pollution liability policy that provides coverage for oil or hazardous substance pollution emanating from a vessel, addressing both Oil Pollution Act of 1990 ("OPA") and CERCLA obligations. This policy also provides coverage for cost of defense, and limited coverage for fines, and penalties up to the applicable policy limits.
We provided services and products to customers in the Gulf of Mexico, generally pursuant to written master services agreements that created insurance and indemnity obligations for both parties. Following the March 2018 sale of our Offshore Division, Orinoco has assumed substantially all of the liabilities of our Offshore Division.
Item 1A. Risk Factors.
Certain Business Risks
Although it is not possible to identify all of the risks we encounter, we have identified the following significant risk factors that could affect our actual results and cause actual results to differ materially from any such results that might be projected, forecasted, or estimated by us in this report.
Market Risks
The demand and prices for our products and services are affected by several factors, including the supply, demand, and prices for oil and natural gas.
Demand for our services and products is particularly sensitive to the level of exploration, development, and production activity of, and the corresponding capital spending by, oil and natural gas companies. The level of exploration, development, and production activity is directly affected by trends in oil and natural gas prices, which historically have been volatile and are likely to continue to be volatile.
Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty, and a variety of other economic factors that are beyond our control. Crude oil prices have fluctuated significantly since 2014, with West Texas Intermediate (WTI) oil spot prices declining from a high of $108 per barrel in June 2014 to a low of $26.19 per barrel in February 2016, a level which has not been experienced since 2003. Although crude oil prices have increased during the second half of 2017 and early 2018 with a high of $66.14 per barrel in January 2018, the volatility of crude oil prices continues
to be high. For more information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Business Environment and Results of Operations.”
The prolonged reduction in oil and natural gas prices depressed levels of exploration, development, and production activity in 2015 and 2016, and if current oil and natural gas prices decrease, they could have a material adverse effect on our business, consolidated results of operations, and consolidated financial condition. Should current market conditions worsen for an extended period of time, we may be required to record additional asset impairments. Such potential impairment charges could have a material adverse impact on our operating results. Even the perception of longer-term lower oil and natural gas prices by oil and natural gas companies can similarly reduce or defer major expenditures given the long-term nature of many large-scale development projects.
Factors affecting the prices of oil and natural gas include: the level of supply and demand for oil and natural gas; governmental regulations, including the policies of governments regarding the exploration for and production and development of their oil and natural gas reserves; weather conditions and natural disasters; worldwide political, military, and economic conditions; the ability or willingness of the Organization of Petroleum Exporting Countries (OPEC) to set and maintain oil production levels; the levels of oil production by non-OPEC countries; oil refining capacity and shifts in end-customer preferences toward fuel efficiency and the use of natural gas; the cost of producing and delivering oil and natural gas; and potential acceleration of the development of alternative fuels.
We encounter,
and expect to continue to encounter,
intense competition in the sale of our products and services.
We compete with numerous companies
in each of our operating segments, many of which
have substantially greater financial and other resources than we have. Certain of our competitors have lower standards of quality and older equipment and safety, and offer services at lower prices than we do. Other competitors have newer equipment that is better suited to our customers' needs. Particularly during a period of low oil and natural gas pricing, to the extent competitors offer products or services at lower prices
or higher quality, or more cost-effective products or services, our business could be materially and adversely affected.
In addition, certain of our customers may elect to perform services internally in lieu of using our services, which could also materially and adversely affect our operations.
The profitability of our operations is dependent on other numerous factors beyond our control.
Our operating results in general, and gross profit in particular, are
determined by
market conditions and the products
and services
we sell
in any period. Other factors, such as heightened competition, changes in sales and distribution channels, availability of skilled labor and contract services, shortages in raw materials, or inability to obtain supplies at reasonable prices, may also affect the cost of sales and the fluctuation of gross margin in future periods.
Other factors affecting our operating results and activity levels include oil and
natural
gas industry spending levels for exploration and production, development, and acquisition activities, and impairments of long-lived assets.
Several of our customers reduced their capital expenditures during 2016 and 2017 in light of the significant declines in the prices of oil and natural gas, and such reductions have had, and are expected to continue to have, a negative effect on the demand for many of our products and services. This has had, and is expected to continue to have, a negative effect on our revenues and results of operations. A large concentration of our operating activities is located in the onshore and offshore U.S. Gulf Coast region. Our revenues and profitability are particularly dependent upon oil and
natural
gas industry activity and spending levels in this region. Our operations may also be affected by technological advances, cost of capital,
and
tax policies. Adverse changes in any of these other factors may
have
a material adverse effect on our revenues and profitability.
Changes in the
economic environment have resulted, and could further result, in further significant impairments of certain of our long-lived assets and goodwill.
During the first quarter of 2016, we recorded consolidated long-lived asset impairments (excluding goodwill impairments) of approximately
$10.7 million
. During the fourth quarter of 2016, primarily as a result of the impact of significant decreases in oil and natural gas prices on certain of our long-lived assets, we recorded consolidated long-lived asset impairments of approximately $7.2 million. During the fourth quarter of
2017
, consolidated long-lived asset impairments of approximately
$14.9 million
were recorded primarily
due to the impairment of a certain
identified intangible asset resulting from decreased expected future operating cash flows from a Production Testing segment customer.
During the two year period ending
December 31, 2017
, we have recorded a total of
$33.0 million
of long-lived asset impairments. Depressed commodity prices and/or adverse changes in the
economic environment could result in a greater decrease in the demand for many of our products and services, which could impact the expected utilization rates of certain of our long-lived assets, including plant facilities, operating locations, barges and vessels, and other operating equipment. Under generally accepted accounting principles, we review the carrying value of our long-lived assets when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable, based on their expected future cash flows. The impact of reduced expected future cash flow could require the write-down of all or a portion of the carrying value for these assets, which would result in additional impairments, resulting in decreased earnings.
During the two year period ending
December 31, 2017
, we have recorded a total of approximately
$106.2 million
of goodwill impairments. Following these goodwill impairments, as of
December 31, 2017
, our consolidated goodwill consists of the $6.6 million of goodwill attributed to our Fluids reporting unit. Under generally accepted accounting principles, we review the carrying value of our goodwill for possible impairment annually or when events or changes in circumstances indicate the carrying value may not be recoverable. Changes in circumstances indicating the carrying value of our goodwill may not be recoverable include a decline in our stock price or future cash flows and slower growth rates in our industry. If economic and market conditions decline, we may be required to record additional charges to earnings during the period in which any impairment of our goodwill is determined, resulting in a negative impact on our results of operations.
We are dependent on third-party suppliers for specific products and equipment necessary to provide certain of our products and services.
We sell a variety of clear brine fluids to the oil and gas industry and non-energy markets, including calcium chloride, calcium bromide, zinc bromide, zinc calcium bromide, sodium bromide, and formate-based brines, some of which we manufacture and some of which are purchased from third parties. Sales of these products contribute significantly to our revenues. In our manufacture of
calcium chloride, we use brines, hydrochloric acid, and other raw materials purchased from third parties. In our manufacture of brominated clear brine fluid products, we use elemental bromine, hydrobromic acid, and other raw materials that are purchased from third parties. We rely on Lanxess as a supplier of bromine for our brominated clear brine fluid products as well as tail brine for our El Dorado, Arkansas, calcium chloride plant. Although we have long-term supply agreements with Lanxess, if we were unable to acquire
these
raw materials
at reasonable prices for a prolonged period, our business could be materially and adversely affected.
The fabrication of our compression packages, pump systems, and production testing, well monitoring,
and rig cooling
equipment requires the purchase of various components, some of which we obtain from a single source or a limited group of suppliers. Our reliance on these suppliers exposes us to the risk of price increases, inferior component quality, or an inability to obtain an adequate supply of required components in a timely manner. The profitability or future growth of our Compression and Production Testing Divisions may be adversely affected due to our dependence
on these key suppliers.
Our success depends upon the continued contributions of our personnel, many of whom would be difficult to replace, and the continued ability to attract new employees.
Our success depends on our ability to attract, train, and retain skilled management and employees at reasonable compensation levels. The delivery of our products and services requires personnel with specialized skills and experience. In addition, our ability to expand our operations depends in part on our ability to increase the size of our skilled labor force. The demand for skilled managers and workers in the U.S. Gulf Coast region and other regions in which we operate is high and the supply is limited. A lack of qualified personnel, could adversely affect operating results.
The demand for our products and services in the U.S. Gulf of Mexico could continue to be adversely impacted by increased regulation and continuing regulatory uncertainty.
Operations in the U.S. Gulf of Mexico have been subject to an increasingly stringent
regulatory environment including government regulations focused on offshore operating requirements, spill cleanup,
and enforcement
matters. These regulations also implement additional safety and certification requirements applicable to offshore activities in the U.S. Gulf of Mexico.
Demand for our products and services in the U.S. Gulf of Mexico continues to be affected by these regulations. Future regulatory requirements could delay our customers’ activities, reduce our revenues, and increase our operating costs, including the cost to insure offshore operations, resulting in reduced cash flows and profitability.
Operating, Technological, and Strategic Risks
We may not fully realize the benefits from the SwiftWater acquisition.
On February 28, 2018, pursuant to the SwiftWater Purchase Agreement dated February 13, 2018, we purchased all of the equity interests in SwiftWater, which is engaged in the business of providing water management and water solutions to oil and gas operators in the Permian Basin market of Texas.
We performed an inspection of SwiftWater's assets, which we believe to be generally consistent with industry practices. However, there could be unknown liabilities or other problems that are not necessarily observable even when the inspection is undertaken. If problems are identified after closing of the SwiftWater acquisition, the purchase agreement provides for limited recourse against the sellers.
We have technological and age-obsolescence risk, both with our products and services as well as with our equipment assets.
New drilling, completion, and production technologies and equipment are constantly evolving. If we are unable to adapt to new advances in technology or replace older assets with new assets, we are at risk of losing customers and market share. In particular, many of our significant equipment assets, are approaching the end of their useful lives, which may adversely affect our ability to serve certain customers. Other equipment, such as a portion of our production testing equipment fleet, may be inadequate to meet the needs of our customers in certain markets. The permanent replacement or upgrade of any of our equipment will require significant capital. Due to the unique nature of many of these assets, finding a suitable or acceptable replacement may be difficult and/or cost prohibitive. The replacement or enhancement of these assets over the next several years may be necessary in order for us to effectively compete in the current marketplace.
We face risks related to our long-term growth strategy.
Our long-term growth strategy includes both internal growth and growth through acquisitions. Internal growth may require significant capital expenditures, some of which may become unrecoverable or fail to generate an acceptable level of cash flows. Internal growth also requires
financial resources (including the use of available cash or additional long-term debt), management, and personnel resources. Acquisitions also require significant management resources, both at the time of the transaction and during the process of integrating the newly acquired business into our operations. If we overextend our current financial resources by growing too aggressively, we could face liquidity problems or have difficulty obtaining additional financing.
Acquisitions could adversely affect our operations
if we are unable to successfully integrate
the
newly acquired companies into our operations, are unable to hire adequate personnel, or are unable to retain existing personnel. We may not be able to consummate future acquisitions on favorable terms. Acquisition or internal growth assumptions developed to support our decisions could prove to be overly optimistic. Future acquisitions by us could result in
issuances of equity securities
or the rights associated with the equity securities, which could potentially dilute earnings per share. Future acquisitions could result in the incurrence of additional debt or contingent liabilities and amortization expenses related to intangible assets. These factors could adversely affect our future operating results and financial position.
Our operations involve significant operating risks and insurance coverage may not be available or cost-effective.
We are subject to operating hazards normally associated with the oilfield service industry, including automobile accidents, fires, explosions, blowouts, formation collapse, mechanical problems, abnormally pressured formations, and environmental accidents. Environmental accidents could include, but are not limited to oil spills, gas leaks or ruptures, uncontrollable flows of oil, gas, or well fluids, or discharges of CBFs or toxic gases or other pollutants. These operating hazards may also include injuries to employees and third parties during the performance of our operations. Our operation of heavy equipment and chemical manufacturing plants involve particularly high levels of risk. In addition, certain of our former employees of the Offshore Services segment
performed services on offshore platforms and vessels and are covered by the provisions of the Jones Act, the Death on the High Seas Act, and general maritime law. These laws make the liability limits established by state workers’ compensation laws inapplicable to these employees and, instead, permit our affected employees or their representatives to pursue actions against us for damages for job-related injuries. Whenever possible, we obtained agreements from customers and suppliers that limit our exposure. However, the occurrence of certain operating hazards, including storms, could result in substantial losses to us due to injury or loss of life, damage to or destruction of property and equipment, pollution or environmental damage, and suspension of operations.
We have maintained a policy of insuring our risks of operational hazards that we believe is typical in the industry. We believe that the limits of insurance coverage we have purchased are consistent with the exposures we face and the nature of our products and services. Due to economic conditions in the insurance industry, from time to time, we have increased our self-insured retentions for certain policies in order to minimize the increased costs of coverage,
or we have reduced our limits of insurance coverage for, or not procured, named windstorm coverage.
In certain areas of our business, we, from time to time, have elected to assume the risk of loss for specific assets. To the extent we suffer losses or claims that are not covered, or are only partially covered by insurance, our results of operations could be adversely affected.
Weather-Related Risks
Certain of our operations are seasonal and depend, in part, on weather conditions.
In certain markets, the Fluids Division’s onshore water management services can be dependent on adequate water supplies being available to its customers. To the extent severe drought or other weather-related conditions prevent our customers from obtaining needed water, frac water operations may not be possible and our Fluids Division business may be negatively affected.
Severe weather, including named windstorms, can cause damage and disruption to our businesses.
A portion of our operations is susceptible to adverse weather conditions in the Gulf of Mexico, including hurricanes and other extreme weather conditions. Even if we do not experience direct damage from storms, we may experience disruptions in our operations, because we are unable to operate or our customers or suppliers may curtail their activities due to damage to their wells, platforms, pipelines, and facilities. From time to time, our onshore operations are also negatively affected by adverse weather conditions, including sustained rain and flooding.
Financial Risks
Failure to comply with the financial ratios in our long-term debt agreements could result in defaults under those agreements
.
As of
December 31, 2017
, our total long-term debt outstanding (excluding CCLP) of
$117.7 million
consisted of the carrying amount of our 11% Senior Note, which was issued under our Amended and Restated Note Purchase Agreement dated as of July 1, 2016, as subsequently amended (the "Amended and Restated 11% Senior Note Agreement"). We currently have
$0.0 million
carrying amount outstanding under our credit agreement, as amended, with a syndicate of banks including JPMorgan Chase Bank, N.A. as administrative agent, which provides us with a secured revolving credit facility with a borrowing capacity of up to $200 million (subject to certain conditions) (the "Credit Agreement"). In addition, as of
December 31, 2017
our consolidated balance sheet includes
$512.2 million
of long-term debt of CCLP, which consisted of (i)
$224.0 million
carrying amount under CCLP's credit agreement, dated as of August 4, 2014, as subsequently amended, with a syndicate of banks including Bank of America, N.A. as administrative agent, which provides CCLP with an asset-based revolving credit facility with a borrowing capacity of up to $315 million, subject to borrowing base requirements (the "CCLP Credit Agreement"), and (ii)
$288.2 million
carrying amount of CCLP's 7.25% Senior Notes due 2022 (the "CCLP 7.25% Senior Notes"), which were issued pursuant to an Indenture, dated as of August 4, 2014, with U.S. Bank National Association, as trustee (the "CCLP Indenture"). Debt service costs related to outstanding long-term debt represent a significant use of our operating cash flow and could increase our vulnerability to general adverse economic and industry conditions.
Each of the Credit Agreement and the Amended and Restated 11% Senior Note Agreement (collectively the "Long-Term Debt Agreements") contains covenants and other restrictions and requirements that, among other things, requires us to maintain certain financial ratios as of the end of each fiscal quarter. Deterioration of these ratios could result in a default under these agreements. Although our Long-Term Debt Agreements include cross-default provisions relating to each other and other indebtedness that we may incur that is greater than a defined amount, there are no cross default provisions, cross collateralization provisions, or cross guarantees between our Long-Term Debt Agreements and CCLP's Credit Agreement or the CCLP Indenture. If an event of default occurs under either of our Long-Term Debt Agreements and such event is not remedied in a timely manner, an event of default will occur under both of the Long-Term Debt Agreements. Any event of default, if not timely remedied, could result in a termination of all commitments of the lenders under the Credit Agreement, acceleration of all amounts owed thereunder and with regard to the 11% Senior Note, and foreclosure on the collateral securing both of the Long-Term Debt Agreements.
Following the Fifth Amendment to the Credit Agreement in December 2016, the financial ratios in the Credit Agreement include a minimum fixed charge coverage ratio (which is the ratio of a defined measure of earnings to interest, both measures over the trailing twelve months) of 1.25 to 1 and a maximum leverage ratio (which is the ratio of (i) outstanding debt under the Long-Term Debt Agreements and certain other obligations, including letters of credit outstanding, to (ii) a measure of our consolidated net earnings ("EBITDA"), all as defined in the Credit Agreement ) of (i) 5.00 to 1 at the end of the fiscal quarters ending during the period from and including March 31, 2017 through and including December 31, 2017, (ii) 4.75 to 1 at the end of the fiscal quarters ending March 31, 2018 and June 30, 2018, (iii) 4.50 to 1 at the end of the fiscal quarters ending September 30, 2018 and December 31, 2018, and (iv) 4.00 to 1 at the end of each of the fiscal quarters thereafter. EBITDA is defined in our Credit Agreement as the aggregate of our net income (or loss) and the net income (or loss) of our consolidated restricted subsidiaries (which excludes CCLP), including cash dividends and distributions (not the return of capital) received from persons (including CCLP) other than consolidated restricted subsidiaries and after allowances for taxes for such period determined on a consolidated basis in accordance with U.S. generally accepted accounting principles ("GAAP"), excluding certain items specifically described therein. This definition of consolidated net earnings excludes an amount of extraordinary and nonrecurring losses up to 25% of a measure of earnings. At December 31, 2016, our fixed charge coverage ratio was
3.05
to 1 and our leverage ratio was
1.66
to 1.
Under the Amended and Restated 11% Senior Note Agreement, the financial ratio requirements include a minimum fixed charge coverage ratio (which is identical to the minimum fixed charge coverage ratio under the Credit Agreement) of 1.25 to 1 and a maximum leverage ratio (which is identical to the maximum leverage ratio under the Credit Agreement) of (i) 5.00 to 1 at the end of the fiscal quarters ending during the period from and including March 31, 2017 through and including December 31, 2017, (ii) 4.75 to 1 at the end of the fiscal quarters ending March 31, 2018 and June 30, 2018, (iii) 4.50 to 1 at the end of the fiscal quarters ending September 30, 2018 and December 31, 2018, and (iv) 4.00 to 1 at the end of the fiscal quarters ending thereafter.
Our continuing ability to comply with covenants in our Long-Term Debt Agreements depends largely upon our ability to generate adequate earnings and operating cash flows. Due to the decreased demand for certain of our products and services by our customers in response to decreased oil and natural gas prices during 2015 and 2016, we reduced long-term debt from the use of equity offering proceeds took strategic cost reduction efforts, including headcount reductions, deferral of salary increases, salary reductions, benefit reductions, and other efforts to reduce costs and generate cash to mitigate the reduced demand for our products and services. We and CCLP are in compliance with all covenants of our respective long-term debt agreements as of
December 31, 2017
. Based on our financial forecasts as of
March 2, 2018
, which are based on certain operating and other business assumptions that we believe to be reasonable, we anticipate that, despite the current industry environment and activity levels, we will have sufficient liquidity, earnings and operating cash flows to maintain compliance with all covenants under our Long-Term Debt Agreements through March 2, 2019. However, there can be no assurance that the assumptions we have made will turn out to be accurate or that we will remain in compliance with these covenants going forward, and we could consequently be in default under our Long-Term Debt Agreements if we were unable to obtain a waiver or amendment from our lenders.
CCLP's failure to comply with the financial ratios in its long-term debt agreements could result in defaults under those agreements and reduced distributions to us.
The CCLP Credit Agreement provides CCLP with an asset-based revolving credit facility with a borrowing capacity of up to $315 million, subject to borrowing base requirements. As of
December 31, 2017
, CCLP's balance sheet includes
$512.2 million
of carrying value of long-term debt of CCLP consisting of (i)
$224.0 million
under the CCLP Credit Agreement and (ii)
$288.2 million
of CCLP 7.25% Senior Notes issued pursuant to the CCLP Indenture. Debt service costs related to CCLP's outstanding long-term debt represents a significant use of its operating cash flow and could increase its vulnerability to general adverse economic and industry conditions. Payment of CCLP's debt service obligations reduces cash available for distribution to its common unitholders, including us. Any breach of, or CCLP's inability to borrow under, the CCLP Credit Agreement, could impact CCLP's ability to fund distributions (if CCLP elected to do so), among other adverse impacts.
The CCLP Credit Agreement, as amended in May 2017, contains financial ratio covenants requiring CCLP to maintain
(i) the consolidated total leverage ratio may not exceed (a) 5.95 to 1 as of March 31, 2017; (b) 6.75 to 1 as of June 30, 2017 and September 30, 2017; (c) 6.50 to 1 as of December 31, 2017 and March 31, 2018; (d) 6.25 to 1 as of June 30, 2018 and September 30, 2018; (e) 6.00 to 1 as of December 31, 2018; and (f) 5.75 to 1 as of March 31, 2019 and thereafter; and (ii) the consolidated secured leverage ratio may not exceed 3.25 to 1 as of the end of any fiscal quarter. The consolidated interest coverage ratio was not amended by the CCLP Fifth Amendment. In addition, the CCLP Fifth Amendment (i) increased the applicable margin by 0.25% in the event the consolidated total leverage ratio exceeds 6.00 to 1, resulting in a range for the applicable margin between 2.00% and 3.50% per annum for LIBOR-based loans and between 1.00% and 2.50% per annum for base-rate loans, depending on the consolidated total leverage ratio, and (ii) modified the appraisal delivery requirement from an annual requirement to a semi-annual requirement. In connection with the CCLP Fifth Amendment, the level of CCLP's cash distributions payable on its common units for the quarterly period ended June 30, 2017 will be limited to the current reduced level. The CCLP Fifth Amendment also included additional revisions that provide flexibility to CCLP for the issuance of preferred securities.
At
December 31, 2017
, the CCLP consolidated total leverage ratio was
6.48
to 1 (compared to 6.50 to 1 maximum allowed under the CCLP Credit Agreement), its consolidated secured leverage ratio was
2.89
to 1 (compared to a 3.25 to 1 maximum ratio allowed under the CCLP Credit Agreement), and its interest coverage ratio was
2.55
to 1 (compared to a 2.25 to 1 minimum ratio required under the CCLP Credit Agreement).
Continued access to the CCLP Credit Agreement is dependent upon CCLP's compliance with the financial ratio covenants as well as the borrowing base and other provisions set forth in the CCLP Credit Agreement. The CCLP Credit Agreement contains additional restrictive provisions ("cash dominion provisions") that are imposed if an event of default has occurred and is continuing or "excess availability" falls below $30.0 million. The CCLP Credit Agreement provides that CCLP may make distributions to holders of its common units, but only if there is no default under the CCLP Credit Agreement and CCLP maintains excess availability of $30.0 million. CCLP's ability to comply with the covenants and restrictions contained in the CCLP Credit Agreement may be affected by events beyond its control, including prevailing economic, financial, and industry conditions. If market or other economic conditions deteriorate, CCLP's ability to comply with these covenants may be impaired. A failure to comply with the provisions of the CCLP Credit Agreement could result in an event of default. Upon an event of default, unless waived, the lenders under the CCLP Credit Agreement would have all remedies available to secured lenders and could elect to terminate their commitments, cease making further loans, require cash collateralization of letters of credit, cause their loans to become due and payable in full, institute foreclosure proceedings against CCLP or its subsidiaries’ assets, and force CCLP and its subsidiaries into bankruptcy or liquidation. If the payment of CCLP's debt is accelerated, its assets may be insufficient to repay such debt in full, and the holders of CCLP common units, including us, could experience a partial or total loss of their investment. An event of default by CCLP under the CCLP Credit Agreement may constitute an event of default under the CCLP 7.25% Senior Notes.
CCLP is in compliance with all covenants of the CCLP Credit Agreement as of
December 31, 2017
. As a result of the recent decreased demand and pricing for certain of CCLP's products and services by CCLP's customers in response to decreased oil and natural gas prices, CCLP reduced long-term debt from the use of the CCLP Preferred Units offering proceeds and taken strategic cost reduction efforts to reduce costs and generate cash. Based on CCLP's financial forecasts as of
February 28, 2018
, which are based on certain operating and other business assumptions that CCLP believes to be reasonable, CCLP anticipates that, despite the current industry environment and activity levels, it will have sufficient earnings and operating cash flows to maintain compliance with all covenants under the CCLP Credit Agreement through February 27, 2019. CCLP's plans and forecasts for 2018 include expectations that we will settle certain expenses owed to us by CCLP pursuant to an Omnibus Agreement previously entered into on June 20, 2011 (as amended, the "Omnibus Agreement") using CCLP common units in
lieu of cash. There can be no assurance that the assumptions CCLP made will turn out to be accurate or that CCLP will remain in compliance with these covenants going forward, and could consequently be in default under the CCLP Credit Agreement if it were unable to obtain a waiver or amendment from its lenders. Any such default under the CCLP Credit Agreement may constitute an event of default under the CCLP 7.25% Senior Notes. As a result, our cash flows could be further affected.
We have continuing exposure to abandonment and decommissioning obligations associated with oil and gas properties previously owned by Maritech.
From 2001 to 2012, Maritech sold oil and gas producing properties in numerous transactions to different buyers. In connection with those sales, the buyers assumed the decommissioning liabilities associated with the properties sold (the "Legacy Liabilities") and generally became the successor operator. Some buyers of these Maritech properties subsequently sold certain of these properties to other buyers, who also assumed the financial responsibilities associated with the properties' operations, and these buyers also typically became the successor operator of the properties. To the extent that a buyer of these properties fails to perform the abandonment and decommissioning work required, a previous owner, including Maritech, may be required to perform the abandonment and decommissioning obligation. As the former parent company of Maritech, we also may be responsible for performing these abandonment and decommissioning obligations. A significant portion of the decommissioning liabilities that were assumed by the buyers of the Maritech properties in these previous sales remains unperformed, and we believe the amounts of these remaining liabilities are significant. We generally monitor the financial condition of the buyers of these properties, and if oil and natural gas pricing levels deteriorate, we expect that one or more of these buyers may be unable to perform the decommissioning work required on properties they acquired, either directly or indirectly from Maritech.
In March 2018, pursuant to a series of transactions, Maritech completed the sales of the remaining active leases held by Maritech to Orinoco and, immediately thereafter, we sold all equity interest in Maritech to Orinoco. Under the Maritech Asset Purchase Agreement, Orinoco assumed all of Maritech's abandonment and decommissioning obligations related to the active leases (the “Orinoco Lease Liabilities”) and under the Maritech Equity Purchase Agreement Orinoco assumed all other liabilities of Maritech, including the Legacy Liabilities, subject to limited exceptions unrelated to the asset retirement obligations. Pursuant to a Bonding Agreement executed in connection with such purchase agreements, Orinoco provided non-revocable bonds in the aggregate amount of $47 million to secure their performance of Maritech’s abandonment and decommissioning obligations related to the Orinoco Lease Liabilities and Maritech’s remaining current abandonment and decommissioning obligations (not including the Legacy Liabilities). If in the future we become liable for any abandonment and decommissioning liability associated with any property previously owned by Maritech other than the Legacy Liabilities, the Bonding Agreement provides that, if we call any of these bonds to satisfy such liability and the amount of the bond payment is not sufficient to pay for such liability, Orinoco will pay us for the additional amount required. To the extent Orinoco is unable to cover any such deficiency or we become liable for a significant portion of the Legacy Liabilities, our financial condition and results of operations may be negatively affected.
We are exposed to significant credit risks.
We face credit risk associated with the significant amounts of accounts receivable we have with our customers in the energy industry. Many of our customers, particularly those associated with our onshore operations, are small- to medium-sized oil and gas operators that may be more susceptible to declines in oil and gas commodity prices or generally increased operating expenses than larger companies. Our ability to collect from our customers is impacted by the current decreased oil and natural gas price environment.
Our operating results and cash flows for certain of our subsidiaries are subject to foreign
currency risk.
The operations of certain of our subsidiaries are exposed to fluctuations between the U.S. dollar
and certain foreign currencies, particularly the euro, the British pound, the Mexican peso, and the Argentinian peso.
Our plans to grow our international operations could cause this exposure from fluctuating currencies to increase.
Historically, exchange rates of foreign currencies have fluctuated significantly compared to the U.S. dollar, and this exchange rate volatility is expected to continue. Significant fluctuations in foreign currencies against the U.S. dollar could adversely affect our balance sheet and results of operations.
The Series A Convertible Preferred Units of CCLP issued on August 2016 and September 2016 (the "CCLP Preferred Units") are senior in right of distributions, liquidation and voting to the common units of CCLP, and will result in the issuance of additional CCLP common units in the future, resulting in dilution of our existing common unit ownership in CCLP, and such dilution is potentially unlimited.
CCLP's partnership agreement does not limit the number of additional common units that CCLP may issue at any time without the approval of its common unitholders. In addition, subject to the provisions of the CCLP partnership agreement and the CCLP Series A Preferred Unit Purchase Agreements, as herein defined, CCLP may issue an unlimited number of partnership units that are senior to the common units in right of distribution, liquidation, or voting. On August 8, 2016, CCLP issued an aggregate of 4,374,454 of CCLP Preferred Units for a cash purchase price of $11.43 per CCLP Preferred Unit (the “Issue Price”), resulting in total net proceeds, after deducting certain offering expenses, of $49.8 million. We purchased 874,891 of the CCLP Preferred Units at the Issue Price, for a purchase price of $10.0 million. Additionally, on
September 20, 2016
, CCLP issued an aggregate of
2,624,672
of Preferred Units for a cash purchase price of
$11.43
per Preferred Unit, resulting in total net proceeds, after deducting certain offering expenses, of
$29.0 million
.
Pursuant to the initial CCLP Series A Preferred Unit Purchase Agreement, our wholly owned CSI Compressco GP Inc. subsidiary (the general partner of CCLP), executed the Second Amended and Restated Agreement of Limited Partnership of the Partnership (the “Amended and Restated CCLP Partnership Agreement”) to, among other things, authorize and establish the rights and preferences of the CCLP Preferred Units. The CCLP Preferred Units are a new class of equity security that ranks senior to CCLP's common units with respect to distribution rights and rights upon liquidation. The holders of CCLP Preferred Units (each, a “CCLP Preferred Unitholder”) will receive quarterly distributions in kind in additional Preferred Units, equal to an annual rate of 11.00% of the Issue Price ($1.2573 per unit annualized), subject to certain adjustments, including adjustments relating to any future issuances of common units below a set price, and any quarterly distributions on our common units in excess of $0.3775 per common unit. In the event CCLP fails to pay in full any quarterly distribution in additional Preferred Units, then until such failure is cured, CCLP is prohibited from making any distributions on its common units. Beginning March 8, 2017 and on the first trading day of each calendar month thereafter for a total of thirty months (each, a “Conversion Date”), the CCLP Preferred Units convert into common units in an amount equal to, with respect to each CCLP Preferred Unitholder, the number of CCLP Preferred Units held by such CCLP Preferred Unitholder divided by the number of Conversion Dates remaining. On June 7, 2017, as permitted under the Amended and Restated CCLP Partnership Agreement, CCLP elected to defer the monthly conversion of CCLP Preferred Units for each of the Conversion Dates during the three month period beginning July 2017. As a result, no CCLP Preferred Units were converted into CCLP common units during the three month period ended September 30, 2017, and future monthly conversions were increased beginning in October 2017. During 2017, conversions of the CCLP Preferred Units resulted in the issuance of 3.7 million CCLP common units. CCLP anticipates that the number of CCLP common units that will be issued upon conversions of the CCLP Preferred Units during 2018 will increase, as monthly conversions are expected during the full year of 2018 and due to the three month deferral of conversions during 2017. CCLP may, at its option, pay cash, or a combination of cash and common units, to the CCLP Preferred Unitholders instead of issuing common units on any Conversion Date, subject to certain restrictions as described in the Amended and Restated CCLP Partnership Agreement and the CCLP Credit Agreement.
Because we own
40%
of the outstanding CCLP common units,
12.6%
of the newly issued CCLP Preferred Units, and approximately
2%
general partner interest in CCLP, as a result of the conversion of the CCLP Preferred Units into CCLP common units:
|
|
•
|
our previously existing ownership interest in the common units of CCLP will decrease;
|
|
|
•
|
the amount of cash available for distribution on each CCLP common unit may decrease;
|
|
|
•
|
the voting power attributable to our previously existing CCLP common units will be diminished; and
|
|
|
•
|
the market price of CCLP common units may decline.
|
We and CCLP are exposed to interest rate risks with regard to our respective credit facility indebtedness.
As of
December 31, 2017
, CCLP has a total of
$224.0 million
outstanding under its revolving credit facility, and we did not have any outstanding borrowings under our revolving credit facility. In connection with the SwiftWater acquisition, we borrowed $40.0 million and we may borrow additional amounts under our revolving credit facility in the future. These revolving credit facilities consist of floating rate loans that bear interest at an agreed upon percentage rate spread (which is determined on our leverage ratio) above London Interbank Offered Rate ("LIBOR"). Accordingly, our cash flows and results of operations could be subject to interest rate risk exposure
associated with the level of the variable rate debt balance outstanding. We currently are not a party to an interest rate swap contract or other derivative instrument designed to hedge our exposure to interest rate fluctuation risk.
Our revolving credit facility is scheduled to mature on September 30, 2019. CCLP's revolving credit facility is scheduled to mature on August 4, 2019. Our 11% Senior Note, which matures November 2022, and CCLP's 7.25% Senior Notes, which mature August 2022, bear interest at fixed interest rates. There can be no assurance that the financial market conditions or borrowing terms at the times these existing debt agreements are renegotiated will be as favorable as the current terms and interest rates.
Legal, Regulatory, and Political Risks
Our operations are subject to extensive and evolving U.S. and foreign federal, state and local laws and regulatory requirements that increase our operating costs and expose us to potential fines, penalties, and litigation.
Laws and regulations govern our operations, including those relating to corporate governance, employees, taxation, fees, importation and exportation restrictions, environmental affairs, health and safety, and the manufacture, storage, handling, transportation, use, and sale of chemical products. Certain foreign countries impose additional restrictions on our activities, such as currency restrictions and restrictions on various labor practices. These laws and regulations are becoming increasingly complex and stringent, and compliance is becoming increasingly expensive. Governmental authorities have the power to enforce compliance with these regulations, and violators are subject to civil and criminal penalties, including civil fines, and injunctions. Third parties may also have the right to pursue legal actions to enforce compliance with certain laws and regulations. It is possible that increasingly strict environmental, health and safety laws, regulations, and enforcement policies could result in substantial costs and liabilities to us.
The EPA is studying the environmental impact of hydraulic fracturing, a process used by the U.S. oil and gas industry in the development of
certain
oil and gas reservoirs. Specifically, the EPA is reviewing the impact of hydraulic fracturing
on drinking water resources.
Certain environmental and other groups have suggested that additional federal, state, and local laws and regulations may be needed to more closely regulate the hydraulic fracturing process.
Several states have adopted regulations that require operators to disclose the chemical constituents in hydraulic fracturing fluids. We cannot predict whether any federal, state or local laws or regulations will be enacted
regarding hydraulic fracturing,
and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed
on oil and gas operators
through the adoption of new laws and regulations,
the
domestic
demand for certain of our products and services
could be
decreased or
subject to delays, particularly for our Production Testing, Compression,
and Fluids Divisions.
We have operations that are either ongoing or scheduled to commence in the U.S. Gulf of Mexico. At this time, we cannot predict the full impact that other regulatory actions that may be mandated by the
federal government
may have on our operations or the operations of our customers. Other governmental or regulatory actions could further reduce our revenues and increase our operating costs, including the cost to insure offshore operations, resulting in reduced cash flows and profitability.
Our
onshore and offshore operations expose
us to risks such as the potential for harmful substances escaping into the environment and causing damages or injuries, which could be substantial. Although we maintain general liability and pollution liability insurance, these policies are subject to exceptions and coverage limits. We maintain limited environmental liability insurance covering named locations and environmental risks associated with contract services for oil and gas operations.
We could be materially and adversely affected by an enforcement proceeding or a claim that is not covered or is only partially covered by insurance.
Because our business depends on the level of activity in the oil and natural gas industry, existing or future laws, regulations, treaties, or international agreements
that impose additional restrictions on the industry may adversely affect our financial results. Regulators are becoming more focused on air emissions from oil and gas operations, including volatile organic compounds, hazardous air pollutants, and greenhouse gases. In particular, the focus on
greenhouse gases and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on our financial results if such laws, regulations, treaties,
or international agreements reduce the worldwide demand for oil and natural gas or otherwise result in reduced economic activity generally. In addition, such laws, regulations, treaties, or international agreements could result in increased compliance costs, capital spending requirements, or additional operating restrictions for us, which may have a negative impact on our financial results.
In addition to increasing our risk of environmental liability, the rigorous enforcement of environmental laws and regulations has accelerated the growth of some of the markets we serve. Decreased regulation and enforcement in the future could materially and adversely affect the demand for certain of the services offered by our Offshore Services operations and, therefore, materially and adversely affect our business.
Our expansion into foreign countries exposes us to complex regulations and may present us with new obstacles to growth.
We plan to
continue to
grow both in the United States and in foreign countries. We have established operations in, among other countries,
Argentina,
Brazil,
Canada,
Finland, Ghana, Mexico,
Norway, Saudi Arabia,
Sweden, and the United Kingdom. Foreign operations carry special risks. Our business in the countries in which we currently operate and those in which we may operate in the future could be limited or disrupted by:
|
|
•
|
restrictions on repatriating cash back to the United States;
|
|
|
•
|
the impact of compliance with anti-corruption laws on our operations and competitive position in affected countries and the risk that actions taken by us or our agents may violate those laws;
|
|
|
•
|
government controls and government actions, such as expropriation of assets and changes in legal and regulatory environments;
|
|
|
•
|
import and export license requirements;
|
|
|
•
|
political, social, or economic instability;
|
|
|
•
|
changes in tariffs and taxes;
and
|
|
|
•
|
our limited knowledge of these markets or our inability to protect our interests.
|
We and our affiliates operate in countries where governmental corruption has been known to exist. While we and our subsidiaries are committed to conducting business in a legal and ethical manner, there is a risk of violating either the U.S. Foreign Corrupt Practices Act, the U.K Bribery Act, or laws or legislation promulgated pursuant to the 1997 OECD Convention on Combating Bribery of Foreign Public Officials in International Business Transactions or other applicable anti-corruption regulations that generally prohibit the making of improper payments to foreign officials for the purpose of obtaining or keeping business. Violation of these laws could result in monetary penalties against us or our subsidiaries and could damage our reputation and, therefore, our ability to do business.
Foreign governments and agencies often establish permit and regulatory standards different from those in the U.S. If we cannot obtain foreign regulatory approvals, or if we cannot obtain them in a timely manner, our growth and profitability from foreign operations could be adversely affected.
Our operations in Argentina expose us to the changing economic, legal, and political environments in that country, including the changing regulations over repatriation of cash generated from our operations in Argentina.
The current economic, legal, and political environment in Argentina and recent devaluation of the Argentinian peso have created increased economic instability for foreign investment in Argentina. The Argentinian government is currently attempting to address the current high rate of inflation and the continuing devaluations pressure. Fiscal and monetary expansion in Argentina has led to devaluations of the Argentinian peso, particularly in late 2013, early 2014, and late 2015. Additional currency adjustment may be necessary to help boost the current Argentina economy, but may be accompanied by fiscal and monetary tightening, including additional restrictions on the purchase of U.S. dollars in Argentina.
As a result of our operations in Argentina, consolidated revenues and operating cash flow generated in Argentina have increased over the past three years. As of
December 31, 2017
, approximately
$0.9 million
of our consolidated cash balance is located in Argentina, and the process of repatriating this cash to the U.S. is subject to increasingly complex regulations. There can be no assurances that our growing Argentinian operations will not expose us to a loss of liquidity, foreign exchange losses, and other potential financial impacts.
Tax laws and regulations may change over time, and the recently passed comprehensive tax reform bill could adversely affect our business and financial condition.
On December 22, 2017, H.R.1, “An Act to Provide the Reconciliation Pursuant to Titles II and V of the Concurrent Resolution on the Budget for Fiscal Year 2018” (the “Act”) (previously known as “The Tax Cuts and Jobs Act”) was signed into law making significant changes to the Internal Revenue Code. The Act, among other things, (i) permanently reduces the U.S. corporate income tax rate, (ii) repeals the corporate alternative minimum tax, (iii) eliminates the deduction for certain domestic production activities, (iv) imposes new limitations on the utilization of net operating losses, and (v) provides for more general changes to the taxation of corporations, including changes to cost recovery rules and to the deductibility of interest expense, which may impact the taxation of oil and gas companies. The Act is complex and far-reaching and we cannot predict with certainty the resulting impact its enactment has on us. The ultimate impact of the Act may differ from our estimates due to changes in interpretations and assumptions made by us as well as additional regulatory guidance that may be issued and any such changes in interpretations or assumptions could adversely affect our business and financial condition. See "Note E - Income Taxes" to our Consolidated Financial Statements for additional information.
Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas our customers produce, while the physical effects of climate change could disrupt production and cause us to incur costs in preparing for or responding to those effects.
The EPA has determined that greenhouse gases ("GHGs")
present an endangerment to public health and the environment,
because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.
Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the Clean Air Act ("CAA"). Such EPA rules
regulate GHG emissions under the CAA and require
a reduction in emissions of GHGs from motor vehicles
and
from certain large stationary sources. The EPA rules also require so-called “green” completions at hydraulically fractured natural gas wells beginning in 2015. In addition, the EPA
also
requires
the
annual reporting
of GHG emissions from specified large GHG emission sources in the United States, including petroleum refineries,
as well as
from
certain oil and gas production facilities.
In addition, in December 2015, over 190 countries, including the United States, reached an agreement to reduce global greenhouse gas emissions (the “Paris Agreement”). The Paris Agreement entered into force in November 2016 after more than 170 nations, including the United States, ratified or otherwise indicated their intent to be bound by the Paris Agreement. However, in June 2017, President Trump announced that the United States intends to withdraw from the Paris Agreement and to seek negotiations either to reenter the Paris Agreement on different terms or a separate agreement. In August 2017, the U.S. Department of State officially informed the United Nations of the United States’ intent to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time. To the extent that the United States and other countries implement the Paris Agreement or impose other climate change regulations on the oil and natural gas industry, it could have an adverse effect on our business.
The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our
facilities
and operations could require us to incur costs.
Further, Congress has considered and almost one-half of the states have adopted legislation that seeks to control or reduce emissions of GHGs from a wide range of sources.
Any such legislation could adversely affect demand for the oil and natural gas our customers produce and, in turn, demand for our
products and services.
Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods,
and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations and cause us to incur costs in preparing for or responding to those effects.
Regulatory initiatives related to hydraulic fracturing in the countries where we and our customers operate could result in operating restrictions or delays in the completion of oil and gas wells that may reduce demand for our services.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from dense subsurface rock formations. The process involves the injection of water, sand or other proppants and chemical additives under pressure into targeted geological formations to fracture the surrounding rock and stimulate production.
Hydraulic fracturing typically is regulated by state oil and gas commissions or similar state agencies, but several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA asserted regulatory authority pursuant to the federal Safe Drinking Water Act (“SDWA”) Underground Injection Control (“UIC”) program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities; published final rules under the federal CAA in 2012 and published additional final regulations in June 2016 governing methane and volatile organic compound (“VOC”) performance standards, including standards for the capture of air emissions released during for the oil and natural gas hydraulic fracturing industry; published in June 2016 an effluent limitations guidelines final rule prohibiting the discharge of waste water from shale natural-gas extraction operations before discharging to a treatment plant; and in 2014 published an Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, the U.S. Bureau of Land Management ("BLM") published a final rule in March 2015 that established new or more stringent standards for performing hydraulic fracturing on federal and Indian lands. However, in June 2016, a Wyoming federal judge struck down this final rule, finding that the BLM lacked authority to promulgate the rule, the BLM appealed the decision to the U.S. Circuit Court of Appeals for the Tenth Circuit in July 2016, the appellate court issued a ruling in September 2017 to vacate the Wyoming trial court decision and dismiss the lawsuit challenging the 2015 rule in response to the BLM’s issuance of a proposed rulemaking to rescind the 2015 rule and, in December 2017, the BLM published a final rule rescinding the March 2015 rule. In January 2018, litigation challenging the BLM’s rescission of the 2015 rule was brought in federal court, but, in June 2016, a Wyoming federal judge struck down this final rule, finding that the BLM lacked authority to promulgate the rule. That decision was appealed by the BLM to the U.S. Circuit Court of Appeals for the Tenth Circuit in 2016, but, in March 2017, the BLM filed a request with the Tenth Circuit to put the appeal on hold pending rescission of the 2015 final rule.
The U.S. Congress (“Congress”) has from time to time considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, some states, including Texas, Oklahoma and New Mexico, where the drilling program is expected to operate, have adopted, and other states are considering adopting legal requirements that could impose new or more stringent permitting, public disclosure, or well construction requirements on hydraulic fracturing activities. States could elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York in 2015. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where the drilling program operates, including, for example, on federal and American Indian lands, the partnership 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. In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under some circumstances. “Water cycle” describes the use of water in hydraulic fracturing, from water withdrawals to the making of hydraulic fracturing fluids, through the mixing and injection of hydraulic fracturing fluids in oil and natural gas production wells, to the collection and disposal or reuse of produced water.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs for our customers in the production of oil and gas, including from the developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of additional regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells and an associated decrease in demand for our services and increased compliance costs and time, which could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.
Regulatory initiatives relating to the protection of endangered or threatened species in the United States, in other countries where we operate, could have an adverse impact on our and our customers’ ability to expand operations.
In the United States, the Endangered Species Act (the “ESA”) restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”). To the extent species that are listed under the ESA or similar state laws, or are protected under the MBTA, live in the areas where we or our customers operate, both our and our customers’ abilities to conduct or expand operations and construct facilities could be limited or be forced to incur material additional costs.
The designation of previously unidentified endangered or threatened species could indirectly cause us to incur additional costs, cause our or our customers’ operations to become subject to operating restrictions or bans, and limit future development activity in affected areas. In addition, as a result of a settlement approved by the United States for the District of Columbia in 2011, the U.S. Fish and Wildlife Service is required to make a determination of listing of numerous species as endangered or threatened under the Endangered Species Act prior to the completion of the agency’s 2017 fiscal year. The designation of previously unprotected species as threatened or endangered in areas where we or our customers might conduct operations could result in limitations or prohibitions on our operations and could adversely impact our business.
Our proprietary rights may be violated or compromised, which could damage our operations.
We own numerous patents, patent applications, and unpatented trade secret technologies in the U.S. and certain foreign countries. There can be no assurance that the steps we have taken to protect our proprietary rights will be adequate to deter misappropriation of these rights. In addition, independent third parties may develop competitive or superior technologies.
Our operations and reputation may be impaired if our information technology systems fail to perform adequately or if we are the subject of a data breach or cyberattack.
Our information technology systems are critically important to operating our business efficiently. We rely on our information technology systems to manage our business data, communications, supply chain, customer invoicing, employee information, and other business processes. We outsource certain business process functions to third-party providers and similarly rely on these third-parties to maintain and store confidential information on their systems. The failure of these information technology systems to perform as we anticipate could disrupt our business and could result in transaction errors, processing inefficiencies, and the loss of sales and customers, causing our business and results of operations to suffer.
Furthermore, our information technology systems may be vulnerable to security breaches beyond our control, including those involving cyberattacks using viruses, worms or other destructive software, process breakdowns, phishing or other malicious activities, or any combination of the foregoing. Such breaches have in the past and could again in the future result in unauthorized access to information including customer, supplier, employee, or other company confidential data. We do not carry insurance against these risks, although we do invest in security technology, perform penetration tests from time to time, and design our business processes to attempt to mitigate the risk of such breaches. However, there can be no assurance that security breaches will not occur. Moreover, the development and maintenance of these measures requires continuous monitoring as technologies change and efforts to overcome security measures evolve. We have experienced, and expect to continue to experience, cyber security threats and incidents, none of which has been material to us to date. However, a successful breach or attack could have a material negative impact on our operations or business reputation and subject us to consequences such as litigation and direct costs associated with incident response.
Item 1B. Unresolved Staff Comments.
None.
Item 2. Properties.
Our properties consist primarily of our corporate headquarters facility, chemical plants, processing plants and distribution facilities. Prior to the March 2018 sale of the Offshore Services segment, our properties also
included heavy lift barge rigs and dive support vessels, each of which are included in the assets owned as of December 31, 2017.
The following information describes facilities that we leased
or owned as of
December 31, 2017
. We believe our facilities are adequate for our present needs.
Facilities
Fluids Division
Our Fluids Division facilities include seven chemical production plants located in the states of Arkansas, California, Louisiana, and West Virginia, and the country of Finland, having a total production capacity of more than 1.5 million equivalent liquid tons per year. The two California locations consist of
29 square miles of leased
mineral
acreage and
solar evaporation ponds, and related owned production and storage facilities.
As an inducement to locate our calcium chloride production plant in Union County, Arkansas, we received certain ad valorem property tax incentives. Our facility
is located just outside the city of El Dorado, Arkansas,
on property that
is leased from Union County, Arkansas. We have the option of purchasing the property at any time during the term of the lease for a nominal price. The term of the lease expires in 2035, at which time we also have the option to purchase the
property
at a nominal price. Under the terms of the lease, we are responsible for all costs incurred related to the facility.
In addition to the production facilities described above, the Fluids Division owns or leases multiple
service center facilities
in the United States and in other countries. The Fluids Division also leases several offices and numerous terminal locations in the United States and in other countries.
We lease approximately 30,000 gross acres of bromine-containing brine reserves in Magnolia, Arkansas, for possible future development and as a source of supply for our bromine and other raw materials.
Production Testing Division
The Production
Testing segment
conducts its operations through production testing service centers (most of which are leased) in the United States, located in
Colorado, Louisiana, North Dakota, Oklahoma,
Pennsylvania, Texas, West Virginia, and Wyoming.
In addition, the Production Testing segment has leased facilities in Australia, Canada, Mexico, and certain countries in the United Kingdom, the Middle East and South America.
Compression Division
The
Compression Division’s
facilities include owned offices and fabrication facilities in Midland, Texas and Oklahoma City, Oklahoma, and several owned and leased service and sales facilities in Argentina, Canada, Mexico, and the United States. All obligations under the bank revolving credit facility for CCLP are secured by a first lien security interest in substantially all of CCLP’s assets, including the Midland, Texas and Oklahoma City, Oklahoma facilities.
For a profile of our compression fleet, see "Item 1. Business "Products and Services - Compression Division."
Offshore Division
The Offshore Division conducts its operations through four
offices and
service facility locations (three
of which are leased) located in Texas and Louisiana. In addition, as of December 31, 2017, the Offshore Services segment owned the following fleet of vessels that it uses in performing its well abandonment, decommissioning, construction, and contract diving operations:
|
|
|
TETRA Hedron
|
Derrick barge with 1,600-metric-ton revolving crane
|
TETRA Arapaho
|
Derrick barge with 725-metric-ton revolving crane
|
Epic Explorer
|
210-foot dive support vessel with saturation diving system
|
We have access to additional leased vessels as needed to adjust to demand for our services. Each of the above properties were sold as part of the March 2018 disposition of our Offshore Division.
Corporate
Our headquarters is located in The Woodlands, Texas, in
a
153,000 square foot office building, which is located on 2.6 acres of land, under a lease that expires in 2027.
In addition, we
own a 28,000 square foot technical facility in The Woodlands, Texas, to service our Fluids Division operations.
Item 3. Legal Proceedings.
We are named defendants in numerous lawsuits and respondents in certain governmental proceedings arising in the ordinary course of business. While the outcome of lawsuits or other proceedings against us cannot be predicted with certainty, management does not consider it reasonably possible that a loss resulting from such lawsuits or other proceedings in excess of any amounts accrued has been incurred that is expected to have a material adverse effect on our financial condition, results of operations, or liquidity.
Environmental Proceedings
One of our subsidiaries, TETRA Micronutrients, Inc. ("TMI"), previously owned and operated a production facility located in Fairbury, Nebraska. TMI is subject to an Administrative Order on Consent issued to American Microtrace, Inc. (n/k/a/ TETRA Micronutrients, Inc.) in the proceeding styled
In the Matter of American Microtrace Corporation
, EPA I.D. No. NED00610550, Respondent, Docket No. VII-98-H-0016, dated September 25, 1998 (the "Consent Order"), with regard to the Fairbury facility. TMI is liable for ongoing environmental monitoring at the Fairbury facility under the Consent Order; however, the current owner of the Fairbury facility is responsible for costs associated with the closure of that facility.
Item 4.
Mine Safety Disclosures.
None.
Notes to Consolidated Financial Statements
December 31, 2017
NOTE A
—
ORGANIZATION AND OPERATIONS
We are a
geographically diversified oil and gas services company, focused on completion fluids and associated products and services, water management, frac flowback, production well testing, offshore rig cooling, and compression services and equipment. Prior to March 2018, our operations also included selected offshore services including well plugging and abandonment, decommissioning, and diving, as well as a limited domestic oil and gas production business.
We were incorporated in Delaware in 1981 and are composed of
five
reporting segments organized into
four
divisions –
Fluids, Production Testing, Compression, and Offshore
. Unless the context requires otherwise, when we refer to “we,” “us,” and “our,” we are describing TETRA Technologies, Inc. and its consolidated subsidiaries on a consolidated basis.
Our
Fluids Division
manufactures and markets clear brine fluids, additives, and associated products and services to the oil and gas industry for use in well drilling, completion and workover operations in the United States and in certain countries in Latin America, Europe, Asia, the Middle East and Africa. The division also markets liquid and dry calcium chloride products manufactured at its production facilities or purchased from third-party suppliers to a variety of markets outside the energy industry. The Fluids Division also provides domestic onshore oil and gas operators with a wide variety of water management services.
Our
Production Testing Division
provides frac flowback, production well testing, offshore rig cooling, and other associated services and early production facilities (EPFs) in many of the major oil and gas producing regions in the United States, Mexico, and Canada, as well as in oil and gas basins in certain regions in South America, Africa, Europe, the Middle East and Australia.
Our
Compression Division
is a provider of compression services and equipment for natural gas and oil production, gathering, transportation, processing, and storage. The Compression Division's equipment sales business includes the fabrication and sale of standard compressor packages, custom-designed compressor packages and oilfield pump systems designed and fabricated at the division's facilities. The Compression Division's aftermarket business provides compressor package reconfiguration and maintenance services and compressor package parts and components manufactured by third-party suppliers. The Compression Division provides its services and equipment to a broad base of natural gas and oil exploration and production, midstream, transmission, and storage companies operating throughout many of the onshore producing regions of the United States, as well as in a number of foreign countries, including Mexico, Canada and Argentina.
Our
Offshore Division
consists of
two
operating segments, both of which were disposed on March 1, 2018: Offshore Services and Maritech. The Offshore Services segment provided services primarily to the offshore oil and gas industry, consisting of: (1) downhole and subsea services, such as well plugging and abandonment and inspection, repair and maintenance services; (2) decommissioning and certain construction services utilizing heavy lift barges and various cutting technologies with regard to offshore oil and gas production platforms and pipelines; and (3) conventional and saturation diving services.
The
Maritech
segment was a limited oil and gas production operation. During 2011 and the first quarter of 2012, Maritech sold substantially all of its oil- and gas-producing property interests. Maritech’s operations consisted primarily of the ongoing abandonment and decommissioning associated with its remaining offshore wells and production platforms.
NOTE B
—
SUMMARY OF
SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
Our consolidated financial statements include the accounts of our wholly owned subsidiaries. We consolidate the financial statements of CCLP as part of our Compression Division, as we determined that CCLP is a variable interest entity and we are the primary beneficiary. We control the financial interests of CCLP and have the
ability to direct the activities of CCLP that most significantly impact its economic performance through our ownership of its general partner. The share of CCLP net assets and earnings that is not owned by us is presented as noncontrolling interest in our consolidated financial statements. Our cash flows from our investment in CCLP are limited to the quarterly distributions we receive on our CCLP common units and general partner interest (including incentive distribution rights) and the amounts collected for services we perform on behalf of CCLP, as TETRA's capital structure and CCLP's capital structure are separate, and do not include cross default provisions, cross collateralization provisions, or cross guarantees. As of
December 31, 2017
, our consolidated balance sheet includes
$95.0 million
of restricted net assets, consisting of the consolidated net assets of CCLP. As our proportionate share of CCLP's net assets exceeds
25.0%
of our consolidated net assets, we have provided condensed parent company financial information in a supplemental schedule accompanying these consolidated financial statements. Our interests in oil and gas properties are proportionately consolidated. All intercompany accounts and transactions have been eliminated in consolidation.
Use of Estimates
The preparation of financial statements in conformity with U.S. generally accepted accounting principles ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclose contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues, expenses, and impairments during the reporting period. Actual results could differ from those estimates, and such differences could be material.
Basis of Presentation
During the fourth quarter of 2016, we adopted the provisions of Accounting Standards Update ("ASU") 2014-15, "Presentation of Financial Statements - Going Concern" ("ASU 2014-15") which requires management to evaluate an entity's ability to continue as a going concern within one year after the date that the financial statements are issued. Disclosures in the notes to the financial statements are required if we conclude that substantial doubt exists or that our plans alleviate substantial doubt that was raised. Pursuant to the provisions of ASU 2014-15, we have determined that, based on our financial forecasts, there are no conditions or events, considered in the aggregate, that raise substantial doubt about our ability to continue as a going concern through one year from the date of issuance of the financial statements. These forecasts are based on certain operating and other business assumptions that we believe to be reasonable as of
March 2, 2018
.
Pursuant to the provisions of ASU 2014-15, CCLP has determined, based on its financial forecasts, that there are no conditions or events, considered in the aggregate, that raise substantial doubt about CCLP's ability to continue as a going concern through one year from the date of issuance of the financial statements. These forecasts are based on certain operating and other business assumptions that CCLP believes to be reasonable as of
March 2, 2018
.
Reclassifications and Adjustments
Certain previously reported financial information has been reclassified to conform to the current year's presentation. The impact of such reclassifications was not significant to the prior year's overall presentation.
Cash Equivalents
We consider all highly liquid cash investments with a maturity of three months or less when purchased to be cash equivalents.
Restricted Cash
Restricted cash is classified as a current asset when it is expected to be repaid or settled in the next twelve month period. Restricted cash reported on our balance sheet as of
December 31, 2016
, consisted primarily of escrowed cash associated with our July 2011 purchase of a heavy lift derrick barge, which was released to the sellers during the third quarter of 2017 and therefore no longer reflected on our balance sheet as of
December 31, 2017
.
Financial Instruments
Financial instruments that subject us to concentrations of credit risk consist principally of trade receivables with companies in the energy industry. Our policy is to evaluate, prior to providing goods or services, each customer's financial condition and to determine the amount of open credit to be extended. We generally require appropriate, additional collateral as security for credit amounts in excess of approved limits. Our customers consist primarily of major, well-established oil and gas producers and independent oil and gas companies.
Payment terms are on a short-term basis. The risk of loss from the inability to collect trade receivables, including certain long-term contractual receivables of our Maritech segment, is heightened during prolonged periods of low oil and natural gas commodity prices.
We have currency exchange rate risk exposure related to transactions denominated in a foreign currency as well as to investments in certain of our international operations. Our risk management activities include the use of foreign currency forward purchase and sale derivative contracts as part of a program designed to mitigate the currency exchange rate risk exposure on selected international operations.
As a result of the outstanding balances under our and CCLP's variable rate revolving credit facilities, we face market risk exposure related to changes in applicable interest rates. Although we have no interest rate swap contracts outstanding to hedge this potential risk exposure, we and CCLP each have fixed interest rate notes, which are each scheduled to mature in 2022 and which mitigate this risk on our consolidated total outstanding borrowings.
Allowances for Doubtful Accounts
Allowances for doubtful accounts are determined
generally and
on a specific identification basis when we believe that the
collection of specific amounts owed to us is not probable.
The changes in allowances for doubtful accounts for the three year period ended
December 31, 2017
, are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
|
|
(In Thousands)
|
At beginning of period
|
|
$
|
6,291
|
|
|
$
|
7,847
|
|
|
$
|
2,485
|
|
Activity in the period:
|
|
|
|
|
|
|
|
|
|
Provision for doubtful accounts
|
|
1,428
|
|
|
2,436
|
|
|
5,387
|
|
Account (chargeoffs) recoveries
|
|
(5,965
|
)
|
|
(3,992
|
)
|
|
(25
|
)
|
At end of period
|
|
$
|
1,754
|
|
|
$
|
6,291
|
|
|
$
|
7,847
|
|
Inventories
Inventories are stated at the lower of cost or market value. Except for work in progress inventory discussed below, cost is determined using the weighted average method. Components of inventories are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2017
|
|
2016
|
|
|
(In Thousands)
|
Finished goods
|
|
$
|
66,377
|
|
|
$
|
62,064
|
|
Raw materials
|
|
4,027
|
|
|
2,429
|
|
Parts and supplies
|
|
38,248
|
|
|
35,548
|
|
Work in progress
|
|
11,402
|
|
|
6,505
|
|
Total inventories
|
|
$
|
120,054
|
|
|
$
|
106,546
|
|
Finished goods inventories include newly manufactured clear brine fluids as well as used brines that are repurchased from certain customers for recycling. Recycled brines are recorded at cost, using the weighted average method. Work in progress inventory consists primarily of new compressor packages located in the CCLP fabrication facility in Midland, Texas. The cost of work in progress is determined using the specific identification method. We write down the value of inventory by an amount equal to the difference between its cost and its estimated market value.
Property, Plant, and Equipment
Property, plant, and equipment are stated at cost. Expenditures that increase the useful lives of assets are capitalized. The cost of repairs and maintenance is charged to operations as incurred. For financial
reporting purposes, we provide for depreciation using the straight-line method over the estimated useful lives of assets, which are
generally
as follows:
|
|
|
|
Buildings
|
|
15 –
40
years
|
Barges and vessels
|
|
5 – 30 years
|
Machinery and equipment
|
|
2 – 20 years
|
Automobiles and trucks
|
|
3 – 4 years
|
Chemical plants
|
|
15 – 30 years
|
Compressors
|
|
12 – 20 years
|
Leasehold improvements are depreciated over the shorter of the remaining term of the associated lease or its useful life.
Depreciation expense, excluding long-lived asset impairments for the years ended
December 31, 2017
,
2016
, and
2015
was
$107.9 million
,
$120.3 million
, and
$138.2 million
, respectively.
Construction in progress as of December 31, 2017 consists primarily of equipment fabrication projects. Construction in progress as of December 31, 2016 consists primarily of capitalized system software development costs incurred which was placed in operation during 2017. Interest capitalized for the years ended
December 31, 2017
,
2016
, and
2015
was
$1.6 million
,
$0.5 million
, and
$0.4 million
, respectively.
Intangible Assets other than Goodwill
Patents, trademarks, and other intangible assets are recorded on the basis of cost and are amortized on a straight-line basis over their estimated useful lives, ranging from
2
to
20
years.
Amortization expense of patents, trademarks, and other intangible assets was
$6.2 million
,
$7.0 million
, and
$14.8 million
for the years ended
December 31, 2017
,
2016
, and
2015
, respectively, and is included in
depreciation, amortization and accretion. The estimated future annual amortization expense of patents, trademarks, and other intangible assets is
$4.7 million
for
2018
,
$4.7 million
for
2019
,
$4.7 million
for
2020
,
$4.4 million
for
2021
, and
$3.9 million
for
2022
.
Intangible assets are tested for recoverability whenever events or changes in circumstances indicate that the carrying value of the asset may not be recoverable. In such an event, we will determine the fair value of the asset using an undiscounted cash flow analysis of the asset at the lowest level for which identifiable cash flows exist. If an impairment has occurred, we will recognize a loss for the difference between the carrying value and the estimated fair value of the intangible asset. During 2017, 2016, and 2015, certain intangible assets were impaired. See "Impairments of Long-Lived Assets" section below.
Goodwill
Goodwill represents the excess of cost over the fair value of the net assets of businesses acquired in purchase transactions. We perform a goodwill impairment test on an annual basis or whenever indicators of impairment are present. We perform the annual test of goodwill impairment following the fourth quarter of each year.
The assessment for goodwill impairment begins with a qualitative assessment of whether it is “more likely than not” that the fair value of each reporting unit is less than its carrying value. This qualitative assessment requires the evaluation, based on the weight of evidence, of the significance of all identified events and circumstances for each reporting unit. Based on this qualitative assessment, we determined that due to the reduced volatility of oil and natural gas commodity prices during 2017 and the improving demand for the products and services for our Fluids Division businesses, it was not “more likely than not” that the fair value of our Fluids reporting unit was less than its carrying value as of
December 31, 2017
.
When the qualitative analysis indicates that it is “more likely than not” that a reporting unit’s fair value is less than its carrying value, the resulting goodwill impairment test consists of a two-step accounting test performed on a reporting unit basis.
The first step of the impairment test is to compare the estimated fair value with the recorded net book value (including goodwill) of our reporting units. If the estimated fair value is higher than the recorded net book value, no impairment is deemed to exist and no further testing is required. If, however, the carrying amount of the
reporting unit exceeds its estimated fair value, an impairment loss is calculated by comparing the carrying amount of the reporting unit’s goodwill to our estimated implied fair value of that goodwill. Our estimates of reporting unit fair value, when required,
are based on a combination of an income and market approach. These estimates are imprecise and are subject to our estimates of the future cash flows of each business and our judgment as to how these estimated cash flows translate into each business’ estimated fair value. These estimates and judgments are affected by numerous factors, including the general economic environment at the time of our assessment, which affects our overall market capitalization.
Because quoted market prices for our reporting units other than Compression are not available, our management must apply judgment in determining the estimated fair value of these reporting units for purposes of performing the goodwill impairment test. Management uses all available information to make these fair value determinations, including the present value of expected future cash flows using discount rates commensurate with the risks involved in the assets. The resultant fair values calculated for the reporting units are then compared to observable metrics for other companies in our industry or to mergers and acquisitions in our industry to determine whether those valuations, in our judgment, appear reasonable.
The accounting principles regarding goodwill acknowledge that the observed market prices of individual trades of a company’s stock (and thus its computed market capitalization) may not be representative of the fair value of the company as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of a single share of that entity’s common stock. Therefore, once the fair value of the reporting units was determined, we also added a control premium to the calculations. This control premium is judgmental and is based on observed mergers and acquisitions in our industry.
As part of our internal annual business outlook for each of our reporting units that we performed during 2015 and 2016, we considered changes in the global economic environment that affected our stock price and market capitalization. As a result of these factors, we determined that it was “more likely than not” that the fair values of certain of our reporting units were less than their respective carrying values as of December 31, 2015 and 2016. As of December 31, 2015, as a result of decreased demand for our products and services due to decreased oil and natural gas commodity prices, and due to decrease in the price of our common stock and the price per common unit of CCLP, we determined that it was "more likely than not" that the fair values of our Compression and Production Testing reporting units were less than their respective carrying values as of December 31, 2015. With regard to the 2016 impairments, due to the decrease in the price of our common stock and the price per common unit of CCLP during the first three months of 2016, our and CCLP's market capitalizations as of March 31, 2016, were below their respective recorded net book values, including remaining goodwill. In addition, the continuing low oil and natural gas commodity price environment resulted in a further negative impact on demand for the products and services for each of our reporting units. As a result of these factors, we determined that it was “more likely than not” that the fair values of our Compression and Production Testing reporting units were less than their respective carrying values as of March 31, 2016. As a result of the goodwill impairment process, we recorded impairments of goodwill of
$177.0 million
and
$106.2 million
as of December 31, 2015 and March 31, 2016, respectively. Following these goodwill impairments, as of
December 31, 2017
, our consolidated goodwill consists of the
$6.6 million
of goodwill attributed to our Fluids reporting unit.
As of
December 31, 2017
, the carrying amount of goodwill for the Fluids, Production Testing, Compression, and Offshore Services reporting units are net of
$23.8 million
,
$111.8 million
,
$231.8 million
and
$27.2 million
, respectively, of accumulated impairment losses.
The changes in the carrying amount of goodwill by reporting unit for the three year period ended
December 31, 2017
, are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fluids
|
|
Production Testing
|
|
Compression
|
|
Offshore Services
|
|
Maritech
|
|
Total
|
|
|
(In Thousands)
|
Balance as of December 31, 2014
|
|
$
|
6,636
|
|
|
$
|
53,682
|
|
|
$
|
233,548
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
293,866
|
|
Goodwill adjustments
|
|
—
|
|
|
(39,775
|
)
|
|
(141,146
|
)
|
|
—
|
|
|
—
|
|
|
(180,921
|
)
|
Balance as of December 31, 2015
|
|
6,636
|
|
|
13,907
|
|
|
92,402
|
|
|
—
|
|
|
—
|
|
|
112,945
|
|
Goodwill adjustments
|
|
—
|
|
|
(13,907
|
)
|
|
(92,402
|
)
|
|
—
|
|
|
—
|
|
|
(106,309
|
)
|
Balance as of December 31, 2016
|
|
6,636
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6,636
|
|
Goodwill adjustments
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
—
|
|
|
—
|
|
Balance as of December 31, 2017
|
|
$
|
6,636
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
6,636
|
|
Impairments of Long-Lived Assets
Impairments of long-lived assets, including identified intangible assets, are determined periodically when indicators of impairment are present. If such indicators are present, the determination of the amount of impairment is based on our judgments as to the future undiscounted operating cash flows to be generated from these assets throughout their
remaining
estimated useful lives. If these undiscounted cash flows are less than the carrying amount of the related asset, an impairment is recognized for the excess of the carrying value over its fair value. Assets held for disposal are recorded at the lower of carrying value or estimated fair value less estimated selling costs.
During the fourth quarter of
2017
, consolidated long-lived asset impairments of approximately
$14.9 million
were recorded primarily
due to the impairment of a certain identified intangible asset resulting from decreased expected future operating cash flows from a Production Testing segment customer.
During the first quarter of 2016, our Compression and Production Testing segments recorded impairments of approximately
$7.9 million
and
$2.8 million
, respectively, due to expected decreased demand due to current market conditions. During the fourth quarter of 2016, our Compression, Offshore, Fluids, and Production Testing segments recorded certain consolidated long-lived asset impairments of approximately
$2.4 million
,
$1.1 million
,
$0.5 million
, and
$3.6 million
, respectively, due to expected decreased demand due to current market conditions.
During the fourth quarter of 2015, our Compression and Production Testing segments recorded impairments of approximately
$6.3 million
and
$12.3 million
, respectively, associated with a portion of the carrying value of certain of long-lived assets due to expected decreased demand, and our Compression segment recorded approximately
$5.7 million
of impairments associated with certain identified intangible assets. Our Fluids Division also recorded impairments of approximately
$19.9 million
associated with certain of its water management business assets.
Decommissioning Liabilities
Related to
Maritech’s remaining oil and gas property decommissioning liabilities, we estimate the third-party fair values (including an estimated profit) to plug and abandon wells, decommission the pipelines and platforms, and clear the sites, and we use these estimates to record Maritech’s decommissioning liabilities, net of amounts allocable to joint interest owners. In March 2018, we closed the Maritech Asset Purchase Agreement with Orinoco that provided for the purchase by Orinoco of the Maritech Properties. Also in March 2018, we finalized the Maritech Equity Purchase Agreement with Orinoco, that provided for the purchase by Orinoco of the Maritech Equity Interests. As a result of these transactions, Orinoco assumed all of Maritech's remaining abandonment and decommissioning obligations,
In estimating the decommissioning liabilities, we performed detailed estimating procedures, analysis, and engineering studies. Whenever practical and cost effective, Maritech utilized the services of its affiliated companies to perform well abandonment and decommissioning work. When these services were performed by an affiliated company, all recorded intercompany revenues were eliminated in the consolidated financial statements. The recorded decommissioning liability associated with a specific property is fully extinguished when the property is completely abandoned. The recorded liability is first reduced by all cash expenses incurred to abandon and decommission the property. If the recorded liability exceeds (or is less than) our actual out-of-pocket costs, the difference is credited (or charged) to earnings in the period in which the work is
performed. We review the adequacy
of our decommissioning liabilities whenever indicators suggest that the estimated cash flows underlying the liabilities have changed materially. The amount of work performed or estimated to be performed on a Maritech property asset retirement obligation may often exceed amounts previously estimated for numerous reasons. Property conditions encountered, including subsea, geological, or downhole conditions, may be different from those anticipated at the time of estimation due to the age of the property and the quality of information available about the particular property conditions. Additionally, the cost of performing work at locations damaged by hurricanes is particularly difficult to estimate due to the unique conditions encountered, including the uncertainty regarding the extent of physical damage to many of the structures. Lastly, previously plugged and abandoned wells have later exhibited a buildup of pressure, which is evidenced by gas bubbles coming from the plugged well head. Remediation work at previously abandoned well sites is particularly costly due to the lack of a platform from which to base these activities. Decommissioning work performed for the years
2017
,
2016
, and
2015
was
$0.6 million
,
$4.0 million
, and
$10.3 million
, respectively. For a further discussion of adjustments and other activity related to Maritech’s decommissioning liabilities, see
Note I
– Decommissioning and Other Asset Retirement Obligations.
Environmental Liabilities
Environmental expenditures that result in additions to property and equipment are capitalized, while other environmental expenditures are expensed. Environmental remediation liabilities are recorded on an undiscounted basis when environmental assessments or cleanups are probable and the costs can be reasonably estimated. Estimates of future environmental remediation expenditures often consist of a range of possible expenditure amounts, a portion of which may be in excess of amounts of liabilities recorded. In such an instance, we disclose the full range of amounts reasonably possible of being incurred. Any changes or developments in environmental remediation efforts are accounted for and disclosed each quarter as they occur. Any recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable.
Complexities involving environmental remediation efforts can cause estimates of the associated liability to be imprecise. Factors that cause uncertainties regarding the estimation of future expenditures include, but are not limited to, the effectiveness of the anticipated work plans in achieving targeted results and changes in the desired remediation methods and outcomes as prescribed by regulatory agencies. Uncertainties associated with environmental remediation contingencies are pervasive and often result in wide ranges of reasonably possible outcomes. Estimates developed in the early stages of remediation can vary significantly. Normally, a finite estimate of cost does not become fixed and determinable at a specific point in time. Rather, the costs associated with environmental remediation become estimable as the work is performed and the range of ultimate cost becomes more defined. It is possible that cash flows and results of operations could be materially affected by the impact of the ultimate resolution of these contingencies.
Revenue Recognition
We recognize revenue using the following criteria: (a) persuasive evidence of an exchange arrangement exists; (b) delivery has occurred or services have been rendered; (c) the buyer’s price is fixed or determinable; and (d) collectability is reasonably assured. Sales terms for our products are FOB shipping point, with title transferring at the point of shipment. Revenue is recognized at the point of transfer of title. Collections associated with progressive billings to customers for the construction of compression equipment by our Compression Division is included in unearned income in the consolidated balance sheets.
Services and Rentals Revenues and Costs
A portion of our services and rentals revenues consists of lease rental income pursuant to operating lease arrangements for compressors and other equipment assets. The following operating lease revenues and associated costs were included in services and rentals revenues and cost of services and rentals, respectively, in the accompanying consolidated statements of operations for each of the following periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2017
|
|
2016
|
|
2015
|
|
(In Thousands)
|
Rental revenue
|
$
|
60,514
|
|
|
$
|
55,909
|
|
|
$
|
143,601
|
|
Rental expenses
|
$
|
19,047
|
|
|
$
|
25,621
|
|
|
$
|
66,528
|
|
Operating Costs
Cost of product sales includes direct and indirect costs of manufacturing and producing our products, including raw materials, fuel, utilities, labor, overhead, repairs and maintenance, materials, services, transportation, warehousing, equipment rentals, insurance, and certain taxes. In addition, cost of product sales includes oil and gas operating expense. Cost of services and rentals includes operating expenses we incur in delivering our services, including labor, equipment rental, fuel, repair and maintenance, transportation, overhead, insurance, and certain taxes. We include in product sales revenues the reimbursements we receive from customers for shipping and handling costs. Shipping and handling costs are included in cost of product sales. Amounts we incur for “out-of-pocket” expenses in the delivery of our services are recorded as cost of services and rentals. Reimbursements for “out-of-pocket” expenses we incur in the delivery of our services are recorded as service revenues. Depreciation, amortization, and accretion includes depreciation expense for all of our facilities, equipment and vehicles, amortization expense on our intangible assets, and accretion expense related to our decommissioning and other asset retirement obligations.
We include in general and administrative expense all costs not identifiable to our specific product or service operations, including divisional and general corporate overhead, professional services, corporate office costs, sales and marketing expenses, insurance, and certain taxes.
Equity-Based Compensation
We and CCLP have various equity incentive compensation plans which provide for the granting of restricted common stock, options for the purchase of our common stock, and other performance-based, equity-based compensation awards to our executive officers, key employees, nonexecutive officers, consultants, and directors. Total equity-based compensation expense, net of taxes, for the three years ended
December 31, 2017
,
2016
, and
2015
, was
$5.0 million
,
$9.5 million
, and
$13.9 million
, respectively. Equity-based compensation expense during 2015 includes an immaterial pre-tax correction of approximately
$6.7 million
. For further discussion of equity-based compensation, see
Note L
– Equity-Based Compensation.
Income Taxes
Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis amounts. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates is recognized as income or expense in the period that includes the enactment date. Beginning in 2014, a portion of the carrying value of certain deferred tax assets is subjected to a valuation allowance. See
Note E
– Income Taxes for further discussion.
Income (Loss) per Common Share
The calculation of basic earnings per share excludes any dilutive effects of options or warrants. The calculation of diluted earnings per share includes the effect of stock options and warrants, if dilutive, which is
computed using the treasury stock method during the periods such options and warrants were outstanding. A reconciliation of the common shares used in the computations of income (loss) per common and common equivalent shares is presented in
Note P
– Income (Loss) Per Share.
Foreign Currency Translation
We have designated the euro, the British pound, the Norwegian krone, the Canadian dollar, the
Brazilian real, the Argentine peso, and the
Mexican peso, respectively, as the functional currency for our operations in Finland and Sweden, the United Kingdom, Norway, Canada, Brazil,
Argentina, and certain of our operations in Mexico. The U.S. dollar is the designated functional currency for all of our other foreign operations. The cumulative translation effect of translating the applicable accounts from the functional currencies into the U.S. dollar at current exchange rates is included as a separate component of
equity. Foreign currency exchange gains and (losses) are included in Other Income (Expense), net, and totaled
$(1.6) million
,
$0.9 million
, and
$(1.7) million
for the years ended
December 31, 2017
,
2016
and
2015
, respectively.
Fair Value Measurements
Fair value is defined as “the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date” within an entity’s principal market, if any. The principal market is the market in which the reporting entity would sell the asset or transfer the liability with the greatest volume and level of activity, regardless of whether it is the market in which the entity will ultimately transact for a particular asset or liability or if a different market is potentially more advantageous. Accordingly, this exit price concept may result in a fair value that may differ from the transaction price or market price of the asset or liability.
Under generally accepted accounting principles, the fair value hierarchy prioritizes inputs to valuation techniques used to measure fair value. Fair value measurements should maximize the use of observable inputs and minimize the use of unobservable inputs, where possible. Observable inputs are developed based on market data obtained from sources independent of the reporting entity. Unobservable inputs may be needed to measure fair value in situations where there is little or no market activity for the asset or liability at the measurement date and are developed based on the best information available in the circumstances, which could include the reporting entity’s own judgments about the assumptions market participants would utilize in pricing the asset or liability.
We utilize fair value measurements to account for certain items and account balances within our consolidated financial statements. Fair value measurements are utilized in the allocation of purchase consideration for acquisition transactions to the assets and liabilities acquired, including intangible assets and goodwill (a level 3 fair value measurement). Fair value measurements are also used in determining the carrying value of certain financial instruments such as the Warrants and the CCLP Preferred Units. In addition, we utilize fair value measurements in the initial recording of our decommissioning and other asset retirement obligations. Fair value measurements may also be utilized on a nonrecurring basis, such as for the impairment of long-lived assets, including goodwill (a level 3 fair value measurement). The fair value of certain of our financial instruments, which include cash, restricted cash, accounts receivable, accounts payable, accrued liabilities, short-term borrowings, and long-term debt pursuant to our bank credit agreements, approximate their carrying amounts. The aggregate fair value of our long-term 11% Senior Note (as such term is herein defined) at
December 31, 2017
and
2016
, was approximately
$130.8 million
and
$133.9 million
, respectively, based on current interest rates on
those dates, which were different from the stated interest rate on the 11% Senior Note. Those fair values compare to face amounts of the 11% Senior Note of
$125.0 million
both at
December 31, 2017
and
2016
. The fair values of the publicly traded CCLP 7.25% Senior Notes (as herein defined) at
December 31, 2017
and
2016
, were approximately
$279.7 million
and
$278.2 million
, respectively, based on current interest rates on
those dates, which were different from the stated interest rate on the CCLP 7.25% Senior Notes. Those fair values compare to a face amount of
$295.9 million
both at
December 31, 2017
and
2016
. See
Note G
- Long-Term Debt and Other Borrowings, for further discussion. We calculated the fair value of our Senior Note as of
December 31, 2017
and
2016
internally, using current market conditions and average cost of debt (a level 2 fair value measurement).
The CCLP Preferred Units are valued using a lattice modeling technique that, among a number of lattice structures, includes significant unobservable items (a level 3 fair value measurement). These unobservable items include (i) the volatility of the trading price of CCLP's common units compared to a volatility analysis of equity prices of CCLP's comparable peer companies, (ii) a yield analysis that utilizes market information related to the debt yields of comparable peer companies, and (iii) a future conversion price analysis. The fair valuation of the CCLP Preferred Units liability is increased by, among other factors, projected increases in CCLP's common unit price, and by
increases in the volatility and decreases in the debt yields of CCLP's comparable peer companies. Increases (or decreases) in the fair value of CCLP Preferred Units will increase (decrease) the associated liability and result in future adjustments to earnings for the associated valuation losses (gains).
The Warrants are valued either by using their traded market prices (a level 1 fair value measurement) or, for periods when market prices are not available, by using the Black Scholes option valuation model that includes estimates of the volatility of the Warrants implied by their trading prices (a level 3 fair value measurement). The fair valuation of the Warrants liability is increased by, among other factors, increases in our common stock price, and by increases in the volatility of our common stock price. Increases (or decreases) in the fair value of the Warrants will increase (decrease) the associated liability and result in future adjustments to earnings for the associated valuation losses (gains).
We also utilize fair value measurements on a recurring basis in the accounting for our foreign currency forward sale derivative contracts. For these fair value measurements, we utilize the quoted value as determined by our counterparty financial institution (a level 2 fair value measurement).
During the third quarter of 2017, we issued a stand-alone, cash-settled stock appreciation rights award to an executive officer. This award is valued by using the Black Scholes option valuation model and such fair value is recognized based on the portion of the requisite service period satisfied as of each valuation date. The fair valuation of the stock appreciation rights liability is increased by, among other factors, increases in our common stock price, and by increases in the volatility of our common stock price. This stock appreciation rights award is reflected as an accrued liability in our consolidated balance sheet. Increases (or decreases) in the fair value of the stock appreciation rights award will increase (decrease) the associated liability and result in future adjustments to earnings for the associated valuation losses (gains).
A summary of these recurring fair value measurements as of
December 31, 2017
, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using
|
|
|
Total as of
|
|
Quoted Prices
in Active
Markets for
Identical
Assets
or Liabilities
|
|
Significant
Other
Observable
Inputs
|
|
Significant
Unobservable
Inputs
|
Description
|
|
Dec 31, 2017
|
|
(Level 1)
|
|
(Level 2)
|
|
(Level 3)
|
|
|
(In Thousands)
|
CCLP Series A Preferred Units
|
|
$
|
(61,436
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(61,436
|
)
|
Warrants liability
|
|
(13,202
|
)
|
|
—
|
|
|
—
|
|
|
(13,202
|
)
|
Cash-settled stock appreciation rights
|
|
(97
|
)
|
|
—
|
|
|
—
|
|
|
(97
|
)
|
Asset for foreign currency derivative contracts
|
|
241
|
|
|
—
|
|
|
241
|
|
|
—
|
|
Liability for foreign currency derivative contracts
|
|
(378
|
)
|
|
—
|
|
|
(378
|
)
|
|
—
|
|
Total
|
|
$
|
(74,872
|
)
|
|
|
|
|
|
|
A summary of these recurring fair value measurements as of
December 31, 2016
, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using
|
|
|
Total as of
|
|
Quoted Prices
in Active
Markets for
Identical
Assets
or Liabilities
|
|
Significant
Other
Observable
Inputs
|
|
Significant
Unobservable
Inputs
|
Description
|
|
Dec 31, 2016
|
|
(Level 1)
|
|
(Level 2)
|
|
(Level 3)
|
|
|
(In Thousands)
|
CCLP Series A Preferred Units
|
|
$
|
(77,062
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(77,062
|
)
|
Warrants liability
|
|
(18,503
|
)
|
|
—
|
|
|
—
|
|
|
(18,503
|
)
|
Asset for foreign currency derivative contracts
|
|
81
|
|
|
—
|
|
|
81
|
|
|
—
|
|
Liability for foreign currency derivative contracts
|
|
(371
|
)
|
|
—
|
|
|
(371
|
)
|
|
—
|
|
Total
|
|
$
|
(95,855
|
)
|
|
|
|
|
|
|
During the fourth quarter of
2017
, our Production Testing segment recorded certain long-lived asset impairments, primarily related to an identified intangible asset resulting from decreased expected future cash flows from a Production Testing segment customer contract. During the fourth quarter of 2016, our Compression, Offshore Services, Fluids, and Production Testing segments recorded certain long-lived asset impairments for assets that were destroyed or no longer considered realizable in the current market. During the first quarter of 2016, our Compression and Production Testing segments recorded additional long-lived asset impairments primarily consisting of goodwill impairments for these segments. Total impairments recorded during 2016 were approximately
$124.4 million
. For further discussion, see "Goodwill" and "Impairment of Long-Lived Assets" section above. The fair values used in these impairment calculations were estimated based on a variety of measurements, including current replacement cost, current market prices (including scrap values) being received for similar assets, and discounted estimated future cash flows, all of which are based on significant unobservable inputs (Level 3) in accordance with the fair value hierarchy.
A summary of these nonrecurring fair value measurements during the year ended
December 31, 2017
, using the fair value hierarchy, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using
|
|
|
|
|
|
|
Quoted Prices
in Active
Markets for
Identical
Assets
or Liabilities (Level 1)
|
|
Significant
Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
|
Year-to-Date
Impairment Losses
|
Description
|
|
Fair Value
|
|
|
|
|
|
|
(In Thousands)
|
Production Testing equipment
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
324
|
|
Production Testing intangible assets
|
|
3,206
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
14,552
|
|
Total
|
|
$
|
3,206
|
|
|
|
|
|
|
|
|
$
|
14,876
|
|
A summary of these nonrecurring fair value measurements during the year ended
December 31, 2016
, using the fair value hierarchy, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using
|
|
|
|
|
Fair Value as of
|
|
Quoted Prices
in Active
Markets for
Identical
Assets
or Liabilities (Level 1)
|
|
Significant
Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
|
Year-to-Date
Impairment Losses
|
Description
|
|
Dec 31, 2016
|
|
|
|
|
|
|
(In Thousands)
|
Compression equipment
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2,357
|
|
Compression intangible assets
|
|
20,600
|
|
(1)
|
—
|
|
|
—
|
|
|
20,600
|
|
|
7,866
|
|
Compression goodwill
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
92,334
|
|
Production Testing equipment
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
3,592
|
|
Production Testing intangible assets
|
|
2,900
|
|
(1)
|
—
|
|
|
—
|
|
|
2,900
|
|
|
2,804
|
|
Production Testing goodwill
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
13,871
|
|
Offshore Services equipment
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,078
|
|
Fluids equipment and facilities
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
218
|
|
Fluids intangible assets
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
257
|
|
Total
|
|
$
|
23,500
|
|
|
|
|
|
|
|
|
$
|
124,377
|
|
(1)
Fair value as of March 31, 2016 date of impairment.
New Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board ("FASB") issued ASU 2014-09, "Revenue from Contracts with Customers." ASU 2014-09 supersedes the revenue recognition requirements in Accounting Standards Codification ("ASC") 605, Revenue Recognition, and most industry-specific guidance. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This ASU is effective for annual periods beginning after December 15, 2017, and interim periods within those years, under either full or modified retrospective adoption. During 2016, in preparation for the adoption of ASU 2014-09, we began a review of the various types of customer contract arrangements for each of our businesses. These reviews include 1) accumulating all customer contractual arrangements; 2) identifying individual performance obligations pursuant to each arrangement; 3) quantifying consideration under each arrangement; 4) allocating consideration among the identified performance obligations; and 5) determining the timing of revenue recognition pursuant to each arrangement. During 2017 we completed these contract reviews and have implemented revised accounting system processes in order to capture information required to be disclosed under ASU 2014-09. We will adopt this new guidance using the modified retrospective method on January 1, 2018. We have substantially completed our analysis of the new guidance and have not identified any material changes to the timing or amount of revenue to be recognized in future periods. The disclosures related to revenue recognition will be significantly expanded under ASU 2014-09, specifically around the quantitative and qualitative information about performance obligations, changes in contract assets and liabilities, and disaggregation of revenue. We continue to evaluate these requirements.
In March 2016, the FASB issued ASU 2016-08, "Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net)" to clarify the guidance on principal versus agent considerations. This ASU does not change the effective date or adoption method under ASU 2014-09 which is noted above.
In April 2016, the FASB issued ASU 2016-10, "Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing" to clarify the guidance on identifying performance obligations
and the licensing implementation guidance. This ASU does not change the effective date or adoption method under ASU 2014-09, which is noted above.
Additionally, in May 2016, the FASB issued ASU 2016-12, "Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients." This ASU addresses and amends several aspects of ASU 2014-09, but does not change the core principle of the guidance. This ASU does not change the effective date or adoption method under ASU 2014-09 which is noted above.
In July 2015, the FASB issued ASU 2015-11, “Simplifying the Measurement of Inventory” (Topic 330), which simplifies the subsequent measurement of inventory by requiring entities to measure inventory at the lower of cost or net realizable value, except for inventory measured using the last-in, first-out (LIFO) or the retail inventory methods. The ASU requires entities to compare the cost of inventory to one measure - net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The ASU is effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods, and is to be applied prospectively with early adoption permitted. As a result of the adoption of this standard during the first quarter of 2017, there was no material impact on our consolidated financial statements.
In February 2016, the FASB issued ASU 2016-02, "Leases" (Topic 842) to increase comparability and transparency among different organizations. Organizations are required to recognize lease assets and lease liabilities on the balance sheet and disclose key information about the leasing arrangements and cash flows. The ASU is effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods, under a modified retrospective adoption with early adoption permitted. We are currently assessing the potential effects of these changes to our consolidated financial statements.
In March 2016, the FASB issued ASU 2016-09, "Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting" as part of a simplification initiative. The update addresses and simplifies several aspects of accounting for share-based payment transactions. The ASU is effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods, with early adoption permitted, and is to be applied using either modified retrospective, retrospective, or prospective transition method based on which amendment is being applied. Upon adoption of ASU 2016-09, we elected to change our accounting policy to account for forfeitures as they occur, using a modified retrospective method and determined that a cumulative-effect adjustment to retained earnings would be immaterial at transition during the first quarter of 2017. Amendments related to accounting for excess tax benefits have been adopted using a prospective transition method and there were no unrealized excess tax benefits prior to adoption that would require a modified retrospective transition method. Prospectively, excess tax benefits for share-based payments, if any, are now included in cash flows from operating activities rather than financing activities. The ASU also requires entities to classify as financing activities on the statement of cash flows, the cash paid to tax authorities when shares are withheld to satisfy the employer’s statutory income tax withholding obligation, with the application of this requirement to be applied retrospectively. As a result of share-based compensation that vested during 2017 and 2016, the impact to the Consolidated Statements of Cash Flows was
$0.8 million
and
$1.7 million
, respectively, of tax remittances on equity based compensation as a financing activity.
In June 2016, the FASB issued ASU 2016-13, "Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments." ASU 2016-13 amends the impairment model to utilize an expected loss methodology in place of the currently used incurred loss methodology, which will result in more timely recognition of losses. ASU 2016-13, which has an effective date of the first quarter of fiscal 2022, also applies to employee benefit plan accounting. We are currently assessing the potential effects of these changes to our consolidated financial statements and employee benefit plan accounting.
In August 2016, the FASB issued ASU 2016-15, "Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments" to reduce diversity in practice in classification of certain transactions in the statement of cash flows. The ASU is effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods, with early adoption permitted, under a retrospective transition adoption. We are currently assessing the potential effects of these changes to our consolidated financial statements.
In November 2016, the FASB issued ASU 2016-16, "Intra-Entity Transfers of Assets Other Than Inventory" which requires companies to account for the income tax effects of intercompany transfers of assets other than inventory when the transfer occurs. The ASU is effective for annual periods beginning after December 15, 2017,
and interim periods within those annual periods, with early adoption permitted, under a modified retrospective transition adoption. We are currently assessing the potential effects of these changes to our consolidated financial statements.
Additionally, in November 2016, the FASB issued ASU 2016-18, "Statement of Cash Flows (Topic 230): Restricted Cash" to reduce diversity in the presentation of restricted cash and restricted cash equivalents in the statement of cash flows. The ASU is effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods, with early adoption permitted, under a retrospective transition adoption. We are currently assessing the potential effects of these changes to our consolidated financial statements.
In January 2017, the FASB issued ASU 2017-04, "Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment" which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. The ASU is effective for annual periods beginning after December 15, 2020, and interim periods within those annual periods, with early adoption permitted, under a prospective adoption. We do not expect the adoption of this standard to have a material impact on our consolidated financial statements.
In May 2017, the FASB issued ASU 2017-09, "Compensation-Stock Compensation (Topic 718): Scope of Modification Accounting" to clarify when to account for a change to the terms or conditions of a share-based payment award as a modification. The ASU is effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods, with early adoption permitted. We do not expect the adoption of this standard to have a material impact on our consolidated financial statements.
In July 2017, the FASB issued ASU 2017-11, "Earnings Per Share (Topic 260); Distinguishing Liabilities from Equity (Topic 480); Derivatives and Hedging (Topic 815): (Part I) Accounting for Certain Financial Instruments with Down Round Features, (Part II) Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Noncontrolling Interests with a Scope Exception" to consider “down round” features when determining whether certain equity-linked financial instruments or embedded features are indexed to an entity’s own stock. Entities that present EPS under ASC 260 will recognize the effect of a down round feature in a freestanding equity-classified financial instrument only when it is triggered. The effect of triggering such a feature will be recognized as a dividend and a reduction to income available to common shareholders in basic EPS. The ASU is effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. We are currently assessing the potential effects of these changes to our consolidated financial statements.
In August 2017, the FASB issued ASU 2017-12, "Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities" to change how companies account for and disclose hedges. The ASU is effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. We are currently assessing the potential effects of these changes to our consolidated financial statements.
NOTE C
— ACQUISITIONS AND DISPOSITIONS
Acquisition of SwiftWater Energy Services
On February 28, 2018, pursuant to a purchase agreement dated February 13, 2018 (the "SwiftWater Purchase Agreement"), we purchased all of the equity interests in SwiftWater Energy Services, LLC ("SwiftWater"), which is engaged in the business of providing water management and water solutions to oil and gas operators in the Permian Basin market of Texas. Under the terms of the SwiftWater Purchase Agreement, consideration of
$40.0 million
of cash, subject to a working capital adjustment, and
7,772,021
shares of our common stock were paid at closing. The sellers will also have the right to receive contingent consideration payments, in an aggregate amount of up to
$15.0 million
, calculated on EBITDA and revenue (each as defined in the SwiftWater Purchase Agreement) of the combined water management business of both SwiftWater and our pre-existing operations in the Permian Basin in respect of the period from January 1, 2018 through December 31, 2019. The contingent consideration may be paid in cash or shares of our common stock, at our election. As of March 2, 2018, a preliminary allocation of the SwiftWater purchase price had yet to be calculated, but will be determined during the first quarter of 2018.
Sale of Offshore Division
On March 1, 2018, we closed a series of related transactions that resulted in the disposition of our Offshore Division. Pursuant to an Asset Purchase and Sale Agreement (the "Maritech Asset Purchase Agreement") with
Orinoco Natural Resources, LLC ("Orinoco") Orinoco purchased certain offshore oil, gas and mineral leases and related assets of Maritech (the "Maritech Properties"). Immediately thereafter, we closed a Membership Interest Purchase and Sale Agreement (the "Maritech Equity Purchase Agreement") with Orinoco, whereby Orinoco purchased all of the equity interests of Maritech (the "Maritech Equity Interests"). Immediately thereafter, we closed an Equity Interest Purchase Agreement (the "Offshore Services Purchase Agreement") with Epic Offshore Specialty, LLC, an affiliate of Orinoco ("Epic Offshore"), whereby Epic Offshore (the "Offshore Services Sale") purchased all of the equity interests in the wholly owned subsidiaries that comprise our Offshore Services segment operations (the "Offshore Services Equity Interests").
Under the terms of the Maritech Asset Purchase Agreement, the Maritech Equity Purchase Agreement, and the Offshore Services Purchase Agreement, the consideration delivered by Orinoco and Epic Offshore for the Maritech Properties, the Maritech Equity Interests and the Offshore Services Equity Interests consisted of (i) the assumption by Orinoco of all of the liabilities and obligations relating to the ownership, operation and condition of the Maritech Properties and the provision of certain indemnities by Orinoco to us under the Maritech Asset Purchase Agreement, (ii) the assumption by Orinoco of all of the liabilities of Maritech and the provision of certain indemnities by Orinoco under the Maritech Equity Purchase Agreement, (iii) the assumption by Epic Offshore of substantially all of the liabilities of the Offshore Services Equity Interests relating to the periods following the closing of the Offshore Services Sale and the provision of certain indemnities by Epic Offshore under the Offshore Services Purchase Agreement, (iv) cash in the amount
$3.1 million
which is equal to the value of the fuel in the vessels owned by Offshore Services as of the closing plus the value (determined to be sixty percent of the amount paid by Offshore Services therefore) of all usable spare parts and supply inventory of Offshore Services, (v) a promissory note in the original principal amount of
$7.5 million
payable by Epic Offshore to us in full, together with interest at a rate of
1.52%
per annum, on December 31, 2019, (vi) performance by Orinoco under a Bonding Agreement executed in connection with the Maritech Asset Purchase Agreement and the Maritech Equity Purchase Agreement whereby Orinoco provided at closing non-revocable performance bonds in an amount equal to
$46.8 million
to cover the performance by Orinoco and Maritech of the asset retirement obligations of Maritech, to be replaced within 90 days of the closing with non-revocable performance bonds, meeting certain requirements, in the sum of
$47.0 million
, and (vii) the delivery of a personal guaranty agreement from Thomas M. Clarke and Ana M. Clarke guaranteeing the payment obligations of Orinoco under the Bonding Agreement (collectively, the "Transaction Consideration").
As a result of these transactions, we are effectively exiting the businesses of our Offshore Services and Maritech segments, and these operations will be reflected as discontinued operations in our consolidated financial statements in future filings beginning with the quarterly period ending March 31, 2018. As a result of these transactions, our consolidated results of operations for the quarterly period ending March 31, 2018, will include a loss on the disposal of our Offshore Division, estimated to range from approximately
$33.0 million
to
$35.0 million
.
NOTE D
— LEASES
We lease some of our transportation equipment, office space, warehouse space, operating locations, and machinery and equipment. Certain facility storage tanks being constructed are leased pursuant to a ten year term, which is classified as a capital lease.
Capitalized costs pursuant to a capital lease are depreciated over the term of the lease.
The office, warehouse, and operating location leases, which vary from one to twenty-five year terms that expire at various dates through
2034
and are
generally
renewable for three and five year periods on similar terms, are classified as operating leases. Transportation equipment leases expire at various dates
through 2029
and
are also classified as operating leases. The office, warehouse, and operating location leases, and machinery and equipment leases generally require us to pay all maintenance and insurance costs.
Future minimum lease payments by year and in the aggregate, under non-cancelable capital and operating leases with terms of one year or more,
and including the headquarters facility lease discussed above,
consist of the following at
December 31, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
Capital Lease
|
|
Operating Leases
|
|
|
(In Thousands)
|
2018
|
|
$
|
108
|
|
|
$
|
16,700
|
|
2019
|
|
108
|
|
|
11,914
|
|
2020
|
|
33
|
|
|
10,515
|
|
2021
|
|
30
|
|
|
8,487
|
|
2022
|
|
—
|
|
|
6,358
|
|
After 2023
|
|
—
|
|
|
36,793
|
|
Total minimum lease payments
|
|
$
|
279
|
|
|
$
|
90,767
|
|
Rental expense for all operating leases was
$33.0 million
,
$30.0 million
, and
$37.1 million
in
2017
,
2016
, and
2015
, respectively.
NOTE E
— INCOME TAXES
On December 22, 2017, the United States enacted significant changes to the U.S. tax law following the passage and signing of H.R.1, “An Act to Provide the Reconciliation Pursuant to Titles II and V of the Concurrent Resolution on the Budget for Fiscal Year 2018” (the “Act”) (previously known as “The Tax Cuts and Jobs Act”). Changes include, but are not limited to, a corporate tax rate decrease from
35%
to
21%
effective for tax years beginning after December 31, 2017, the transition of U.S. international taxation from a worldwide tax system to a territorial system, and a one-time transition tax on the mandatory deemed repatriation of cumulative foreign earnings as of December 31, 2017. We have calculated our best estimate of the impact of the Act in our year-end income tax provision in accordance with our understanding of the Act and guidance available as of the date of this filing and as result have recorded income tax expense of
$54.1 million
in the fourth quarter of 2017, the period in which the legislation was enacted. This income tax expense was fully offset by a decrease in the valuation allowance previously recorded on our net deferred tax assets. As such, the Act resulted in no net tax expense. The provisional amount related to the remeasurement of certain deferred tax assets and liabilities, based on the rates at which they are expected to reverse in the future was
$49.6 million
, offset by a corresponding decrease in our valuation allowance. The provisional amount related to the one-time transition tax was
$4.5 million
, offset by a corresponding decrease in our valuation allowance.
On December 22, 2017, Staff Accounting Bulletin 118 (“SAB 118”) was issued to address the application of US GAAP in situations when a registrant does not have the necessary information available, prepared, or analyzed (including computations) in reasonable detail to complete the accounting for certain income tax effects of the Act. We have made reasonable estimates of the effects and recorded provisional amounts in our financial statement as of December 31, 2017. However, we are still analyzing certain aspects of the Act and refining our calculations, which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts.
We have not yet completed our calculation of the total post-1986 E&P for these foreign subsidiaries. Further, the transition tax is based in part on the amount of those earnings held in cash and other specified assets. This amount may change when we finalize the calculation of post-1986 foreign E&P previously deferred from US federal taxation and finalize the amounts held in cash or other specified assets.
In January 2018, the FASB released guidance on the accounting for tax on the global intangible low-taxed income ("GILTI") provisions of the Act. The GILTI provisions impose a tax on foreign income in excess of a deemed return on tangible assets of foreign corporations. The guidance indicates that either accounting for deferred taxes related to GILTI inclusions or to treat any taxes on GILTI inclusions as period cost are both acceptable methods subject to an accounting policy election. A provisional estimate could not be made as we have not yet completed our assessment or elected an accounting policy to either recognize deferred taxes for basis differences expected to reverse as GILTI or to record GILTI as period costs if and when incurred.
No additional income taxes have been provided for any remaining undistributed foreign earnings not subject to the transition tax, or any additional outside basis difference inherent in these entities, as these amounts continue to be indefinitely reinvested in foreign operations. Determining the amount of unrecognized deferred tax liability related to any remaining undistributed foreign earnings not subject to the transition tax and additional outside basis difference in these entities (i.e., basis difference in excess of that subject to the one-time transition tax) is not practicable.
The income tax provision (benefit) attributable to continuing operations for the years ended
December 31, 2017
,
2016
,
and
2015
,
consists of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
|
|
(In Thousands)
|
Current
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
(651
|
)
|
|
$
|
—
|
|
|
$
|
(1,310
|
)
|
State
|
|
799
|
|
|
783
|
|
|
2,022
|
|
Foreign
|
|
4,100
|
|
|
3,328
|
|
|
7,371
|
|
|
|
4,248
|
|
|
4,111
|
|
|
8,083
|
|
Deferred
|
|
|
|
|
|
|
|
|
|
Federal
|
|
686
|
|
|
—
|
|
|
191
|
|
State
|
|
(648
|
)
|
|
(610
|
)
|
|
(1,613
|
)
|
Foreign
|
|
(3,086
|
)
|
|
(1,198
|
)
|
|
1,043
|
|
|
|
(3,048
|
)
|
|
(1,808
|
)
|
|
(379
|
)
|
Total tax provision (benefit)
|
|
$
|
1,200
|
|
|
$
|
2,303
|
|
|
$
|
7,704
|
|
A reconciliation of the provision (benefit) for income taxes attributable to continuing operations, computed by applying the federal statutory rate
to income (loss) before income taxes and the reported income taxes, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
|
|
(In Thousands)
|
Income tax provision (benefit) computed at statutory federal income tax rates
|
|
$
|
(21,344
|
)
|
|
$
|
(82,982
|
)
|
|
$
|
(70,617
|
)
|
State income taxes (net of federal benefit)
|
|
1,664
|
|
|
(2,960
|
)
|
|
(608
|
)
|
Nondeductible meals and entertainment
|
|
472
|
|
|
419
|
|
|
909
|
|
Impact of international operations
|
|
10,860
|
|
|
7,567
|
|
|
(1,880
|
)
|
Impact of U.S. tax law change
|
|
54,092
|
|
|
—
|
|
|
—
|
|
Goodwill impairments
|
|
—
|
|
|
12,990
|
|
|
20,412
|
|
Impact of noncontrolling interest
|
|
5,151
|
|
|
2,247
|
|
|
1,411
|
|
Valuation allowance
|
|
(55,850
|
)
|
|
58,846
|
|
|
55,392
|
|
Other
|
|
6,155
|
|
|
6,176
|
|
|
2,685
|
|
Total tax provision (benefit)
|
|
$
|
1,200
|
|
|
$
|
2,303
|
|
|
$
|
7,704
|
|
Other reconciling items for 2017 include
$6.2 million
related to a cumulative correcting cost allocation adjustment between CCLP U.S. subsidiary entities from prior years, the net impact from which is considered immaterial.
Income (loss) before taxes and discontinued operations includes the following components:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
|
|
(In Thousands)
|
Domestic
|
|
$
|
(46,356
|
)
|
|
$
|
(235,394
|
)
|
|
$
|
(195,815
|
)
|
International
|
|
(14,627
|
)
|
|
(1,696
|
)
|
|
(5,948
|
)
|
Total
|
|
$
|
(60,983
|
)
|
|
$
|
(237,090
|
)
|
|
$
|
(201,763
|
)
|
A reconciliation of the beginning and ending amount of our gross unrecognized tax benefit liability is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
|
|
(In Thousands)
|
Gross unrecognized tax benefits at beginning of period
|
|
$
|
1,593
|
|
|
$
|
1,955
|
|
|
$
|
1,959
|
|
Decreases in tax positions for prior years
|
|
—
|
|
|
—
|
|
|
—
|
|
Increases in tax positions for current year
|
|
—
|
|
|
16
|
|
|
120
|
|
Lapse in statute of limitations
|
|
(327
|
)
|
|
(378
|
)
|
|
(124
|
)
|
Gross unrecognized tax benefits at end of period
|
|
$
|
1,266
|
|
|
$
|
1,593
|
|
|
$
|
1,955
|
|
We recognize interest and penalties related to uncertain tax positions in income tax expense. During the years ended
December 31, 2017
,
2016
, and
2015
, we
recognized
$(0.2) million
,
$(0.1) million
, and
$0.3 million
,
respectively, of
interest and penalties to the provision for income tax. As of
December 31, 2017
and
2016
, we had
$2.0 million
and
$2.3 million
, respectively, of accrued potential interest and penalties associated with these uncertain tax positions. The total amount of unrecognized tax benefits that would affect our effective tax rate if recognized is
$3.1 million
and
$3.2 million
as of
December 31, 2017
and
2016
, respectively. We do not expect a significant change to the unrecognized tax benefits during the next twelve months.
We file tax returns in the U.S. and in various state, local, and non-U.S. jurisdictions. The following table summarizes the earliest tax years that remain subject to examination by taxing authorities in any major jurisdiction in which we operate:
|
|
|
Jurisdiction
|
Earliest Open Tax Period
|
United States – Federal
|
2012
|
United States – State and Local
|
2002
|
Non-U.S. jurisdictions
|
2011
|
We use the liability method for reporting income taxes, under which current and deferred tax assets and liabilities are recorded in accordance with enacted tax laws and rates. Under this method, at the end of each period, the amounts of deferred tax assets and liabilities are determined using the tax rate expected to be in effect when the taxes are actually paid or recovered. We establish a valuation allowance to reduce the deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. We considered all available evidence, both positive and negative, in determining whether, based on the weight of that evidence, a valuation allowance is needed for some portion or all of our deferred tax assets. In determining the need for a valuation allowance on our deferred tax assets we placed greater weight on recent and objectively verifiable current information, as compared to more forward-looking information that is used in valuating other assets on the balance sheet. While we have considered taxable income in prior carryback years, future reversals of existing taxable temporary differences, future taxable income, and tax planning strategies in assessing the need for the valuation allowance, there can be no guarantee that we will be able to realize all of our deferred tax assets. Significant components of our deferred tax assets and liabilities as of
December 31, 2017
and
2016
,
are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2017
|
|
2016
|
|
|
(In Thousands)
|
Net operating losses
|
|
$
|
88,025
|
|
|
$
|
126,141
|
|
Foreign tax credits and alternative minimum tax credits
|
|
19,346
|
|
|
28,929
|
|
Accruals
|
|
24,577
|
|
|
31,835
|
|
Depreciation and amortization for book in excess of tax expense
|
|
40,979
|
|
|
67,183
|
|
All other
|
|
3,813
|
|
|
8,932
|
|
Total deferred tax assets
|
|
176,740
|
|
|
263,020
|
|
Valuation allowance
|
|
(130,453
|
)
|
|
(185,275
|
)
|
Net deferred tax assets
|
|
$
|
46,287
|
|
|
$
|
77,745
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2017
|
|
2016
|
|
|
(In Thousands)
|
Depreciation and amortization for tax in excess of book expense
|
|
$
|
48,618
|
|
|
$
|
83,311
|
|
All other
|
|
2,064
|
|
|
1,702
|
|
Total deferred tax liability
|
|
50,682
|
|
|
85,013
|
|
Net deferred tax liability
|
|
$
|
4,395
|
|
|
$
|
7,268
|
|
We believe that it is more likely than not we will not realize all the tax benefits of the deferred tax assets within the allowable carryforward period. Therefore, an appropriate valuation allowance has been provided. The valuation allowance as of December 31,
2017
and
2016
primarily relates to
federal deferred tax assets. The increase (decrease) in the valuation allowance during the years ended
December 31, 2017
,
2016
, and
2015
, were
$(54.8) million
,
$58.6 million
, and
$53.0 million
, respectively.
At
December 31, 2017
, we had federal, state, and foreign net operating loss carryforwards/carrybacks equal to approximately
$62.3 million
,
12.8 million
, and
12.9 million
, respectively. In those countries and states in which net operating losses are subject to an expiration period, our loss carryforwards, if not utilized, will expire at various dates from
2017
through 2036. At
December 31, 2017
, we had
$19.1 million
of foreign tax credits available to offset future payment of federal income taxes. The foreign tax credits expire in varying amounts from
2020 through 2025. Utilization of the net operating loss and credit carryforwards may be subject to a significant annual limitation due to ownership changes that have occurred previously or could occur in the future provided by Section 382 of the Internal Revenue Code.
NOTE F
— ACCRUED LIABILITIES
Accrued liabilities are detailed as follows:
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2017
|
|
2016
|
|
|
(In Thousands)
|
Compensation and employee benefits
|
|
$
|
22,298
|
|
|
$
|
12,681
|
|
Accrued interest
|
|
9,272
|
|
|
9,335
|
|
Accrued capital expenditures
|
|
2,869
|
|
|
6,782
|
|
Accrued taxes
|
|
13,860
|
|
|
11,857
|
|
Other accrued liabilities
|
|
21,091
|
|
|
15,011
|
|
Total accrued liabilities
|
|
$
|
69,390
|
|
|
$
|
55,666
|
|
NOTE G
— LONG-TERM DEBT AND OTHER BORROWINGS
We believe TETRA's capital structure and CCLP's capital structure should be considered separately, as there are no cross default provisions, cross collateralization provisions, or cross guarantees between CCLP's debt and TETRA's debt.
Long-term debt consists of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
2017
|
|
December 31,
2016
|
|
|
|
(In Thousands)
|
TETRA
|
|
Scheduled Maturity
|
|
|
|
Bank revolving line of credit facility (presented net of the unamortized deferred financing costs of $2.3 million as of December 31, 2016)
|
|
September 30, 2019
|
$
|
—
|
|
|
$
|
3,229
|
|
11.0% Senior Note, Series 2015 (presented net of the unamortized discount of $3.9 million as of December 31, 2017 and $4.4 million as of December 31, 2016 and net of unamortized deferred financing costs of $3.4 million as of December 31, 2017 and $4.2 million as of December 31, 2016)
|
|
November 5, 2022
|
117,679
|
|
|
116,411
|
|
TETRA total debt
|
|
|
117,679
|
|
|
119,640
|
|
Less current portion
|
|
|
—
|
|
|
—
|
|
TETRA total long-term debt
|
|
|
$
|
117,679
|
|
|
$
|
119,640
|
|
|
|
|
|
|
|
CCLP
|
|
|
|
|
|
CCLP Bank Credit Facility (presented net of the unamortized deferred financing costs of $4.0 million as of December 31, 2017 and $4.5 million as of December 31, 2016)
|
|
August 4, 2019
|
223,985
|
|
|
217,467
|
|
CCLP 7.25% Senior Notes (presented net of the unamortized discount of $2.8 million as of December 31, 2017 and $3.3 million as of December 31, 2016 and net of unamortized deferred financing costs of $5.0 million as of December 31, 2017 and $6.0 million as of December 31, 2016)
|
|
August 15, 2022
|
288,191
|
|
|
286,623
|
|
CCLP total debt
|
|
|
512,176
|
|
|
504,090
|
|
Less current portion
|
|
|
—
|
|
|
—
|
|
CCLP total long-term debt
|
|
|
512,176
|
|
|
504,090
|
|
Consolidated total long-term debt
|
|
|
$
|
629,855
|
|
|
$
|
623,730
|
|
Scheduled maturities for the next five years and thereafter are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2017
|
|
|
(In Thousands)
|
|
|
TETRA
|
|
CCLP
|
|
Consolidated
|
2018
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
2019
|
|
—
|
|
|
223,985
|
|
|
223,985
|
|
2020
|
|
—
|
|
|
—
|
|
|
—
|
|
2021
|
|
—
|
|
|
—
|
|
|
—
|
|
2022
|
|
117,679
|
|
|
288,191
|
|
|
405,870
|
|
Thereafter
|
|
—
|
|
|
—
|
|
|
—
|
|
Total maturities
|
|
$
|
117,679
|
|
|
$
|
512,176
|
|
|
$
|
629,855
|
|
As of
December 31, 2017
, TETRA (excluding CCLP) had
no
outstanding balance and
had
$5.0 million
in letters of credit against its secured revolving credit facility with a borrowing capacity of up to
$200 million
(subject to certain conditions), leaving a net availability of
$194.9 million
. Because there was no outstanding balance on this Credit Agreement, associated deferred financing costs of
$1.5 million
as of
December 31, 2017
, were classified as other long-term assets on the accompanying consolidated balance sheet. As of
December 31, 2017
, CCLP had an outstanding balance of
$228.0 million
and had
$7.2 million
letters of credit outstanding against the CCLP Credit Agreement, leaving a net availability of
$79.8 million
, subject to a borrowing base limitation. Availability under each of the TETRA Credit Agreement and the CCLP Credit Agreement is subject to compliance with the covenants and other provisions in the respective credit agreements that may limit borrowings thereunder. See below for further discussion of the CCLP Credit Agreement.
As described below, we and CCLP are in compliance with all covenants of our respective credit agreements and senior note agreements as of
December 31, 2017
.
The following discussion is not a complete description of our or CCLP's long-term debt agreements or amendments and is qualified in its entirety by reference to the full text of the complete agreements and amendments, which are filed as an exhibit to our and CCLP's filings with the Securities and Exchange Commission ("SEC").
Our Long-Term Debt
Our Bank Credit Agreement
.
Under our credit agreement, as amended (the "Credit Agreement"), with a syndicate of banks including JPMorgan Chase Bank, N.A. as administrative agent, we have a secured revolving credit facility with a borrowing capacity of up to
$200 million
(subject to certain conditions) which matures on September 30, 2019. Borrowings generally bear interest at the British Bankers Association LIBOR rate plus 2.50% to 4.25%, depending on one of our financial ratios. We pay a commitment fee ranging from
0.35%
to
1.00%
on unused portions of the facility. All obligations under the Credit Agreement and the guarantees of such obligations are secured by first-lien security interests in substantially all of our assets and the assets of our subsidiaries other than CCLP and its subsidiaries (limited, in the case of foreign subsidiaries, to 66% of the voting stock or equity interests of first-tier foreign subsidiaries). Such security interests are for the benefit of the lenders of the Credit Agreement as well as the holder of our 11% Senior Note. In addition, the Credit Agreement includes limitations on aggregate asset sales, individual acquisitions, and aggregate annual acquisitions and capital expenditures.
Our Credit Agreement contains customary covenants and other restrictions, including certain financial ratio covenants based on our levels of debt and interest cost compared to a defined measure of operating cash flows ("EBITDA") over a twelve month period. Access to our revolving credit line is dependent upon our compliance with the financial ratio covenants set forth in the Credit Agreement. Consolidated net earnings under the credit facility is defined as the aggregate of our net income (or loss) and our consolidated restricted subsidiaries (which does not include CCLP), including cash dividends and distributions (not the return of capital) received from persons other than consolidated restricted subsidiaries (including CCLP) and after allowances for taxes for such period determined on a consolidated basis in accordance with U.S. generally accepted accounting principles ("GAAP"), excluding certain items more specifically described therein. The Credit Agreement includes cross-default provisions relating to any other indebtedness (excluding indebtedness of CCLP) greater than a defined amount. Our Credit Agreement also contains a covenant that restricts us from paying dividends in the event of a default or if such payment would result in an event of default.
On July 1, 2016, we entered into an amendment (the "Fourth Amendment") of our Credit Agreement that replaced and modified certain covenants in the Credit Agreement. Pursuant to the Fourth Amendment, the interest charge coverage ratio covenant was deleted and replaced with a fixed charge coverage ratio covenant. The fixed charge coverage ratio may not be less than 1.25 to 1 as of the end of any fiscal quarter. The Fourth Amendment also amended the consolidated leverage ratio covenant, which was further amended in December 2016. The Fourth Amendment also resulted in additional modifications, including a requirement that all obligations under the Credit Agreement and the guarantees of such obligations be secured by first-lien security interests in substantially all of our assets and the assets of our subsidiaries (limited, in the case of foreign subsidiaries, to 66% of the voting stock or equity interests of first-tier foreign subsidiaries). Such security interests are for the benefit of the lenders of the Credit Agreement as well as the holder of our 11% Senior Note. Pursuant to the Fourth Amendment, bank fees and other financing costs of
$0.8 million
were deferred.
On December 22, 2016, we entered into an amendment (the "Fifth Amendment") of our Credit Agreement that replaced and modified certain covenants. Pursuant to the Fifth Amendment, the consolidated leverage ratio may not exceed (a) 5.00 to 1 at the end of fiscal quarters ending during the period from and including March 31, 2017 through and including December 31, 2017, (b) 4.75 to 1 at the end of fiscal quarters ending March 31, 2018 and June 30, 2018, (c) 4.50 to 1 at the end of fiscal quarters ending September 30, 2018 and December 31, 2018, and (d) 4.00 to 1 at the end of each of the fiscal quarters thereafter. In addition, the Fifth Amendment provides for the reduction of the maximum aggregate lender commitments from
$225 million
to
$200 million
, along with various other changes that can be found in the Fifth Amendment. Borrowings under our Credit Agreement following the Fifth Amendment generally bear interest at the British Bankers Association LIBOR rate, or an alternate base rate, in each case plus 2.50% to 4.25%, depending on our consolidated leverage ratio. We pay a commitment fee ranging from
0.35%
to
1.00%
on unused portions of the facility, also depending on our consolidated leverage ratio. Pursuant to the Fifth Amendment, bank fees and other financing costs of
$0.8 million
were deferred. As a result of the reduction of the aggregate lender commitments pursuant to the Fifth Amendment, unamortized deferred finance costs of
$0.2 million
were charged to interest expense during the year ended December 31, 2016.
At
December 31, 2017
, our consolidated leverage ratio was
1.66
to 1 (compared to a 5.00 to 1 maximum allowed under the Credit Agreement). Our fixed charge coverage ratio as of
December 31, 2017
was
3.05
to 1 (compared to a 1.25 to 1 minimum required under the Credit Agreement).
Our 11% Senior Note
.
As of
December 31, 2017
, our senior note consists of the 11% Senior Note that was issued and sold in November 2015 pursuant to our 11% Senior Note Agreement with GSO Tetra Holdings LP ("GSO") whereby we issued and sold
$125.0 million
in principal amount of our 11% Senior Note (the "11% Senior Note"). The 11% Senior Note bears interest at the fixed rate of
11.0%
and matures on
November 5, 2022
. Interest on the 11% Senior Note is due quarterly on March 15, June 15, September 15, and December 15 of each year. We may prepay the 11% Senior Note, in whole or in part at a prepayment price equal to (i) prior to November 20, 2018, 100% of the principal amount so prepaid, plus accrued and unpaid interest and a “make-whole” prepayment amount, (ii) during the period commencing on November 20, 2018, and ending on November 19, 2019, 104% of the principal amount so prepaid, plus accrued and unpaid interest, (iii) during the period commencing on November 20, 2019 and ending on November 19, 2020, 102% of the principal amount so prepaid, plus accrued and unpaid interest, (iv) during the period commencing on November 20, 2020, and ending on November 19, 2021, 101% of the principal amount so prepaid, plus accrued and unpaid interest, and (v) on or after November 20, 2021, 100% of the principal amount so prepaid, plus accrued and unpaid interest.
The 11% Senior Note is guaranteed by substantially all of our wholly owned U.S. subsidiaries. The 11% Senior Note Agreement contains customary covenants that limit our ability and the ability of certain of our restricted subsidiaries to, among other things: incur or guarantee additional indebtedness; incur or create liens; merge or consolidate or sell substantially all of our assets; engage in a different business; enter into transactions with affiliates; and make certain payments. In addition, the 11% Senior Note Agreement requires us to maintain certain financial ratios, including a maximum leverage ratio (ratio of debt and letters of credit outstanding to a defined measure of earnings). The maximum leverage ratio is further defined in our 11% Senior Note Agreement. Consolidated net earnings under the 11% Senior Note Agreement is the aggregate of our net income (or loss) and our consolidated restricted subsidiaries, including cash dividends and distributions (not the return of capital) received from persons other than consolidated restricted subsidiaries (such as CCLP) and after allowances for taxes for such period determined on a consolidated basis in accordance with U.S. GAAP, excluding certain items more specifically described therein. CCLP is an unrestricted subsidiary and is not a borrower or a guarantor under our 11% Senior Note Agreement.
The 11% Senior Note Agreement includes cross-default provisions relating to other indebtedness (excluding CCLP) greater than a defined amount. Upon the occurrence and during the continuation of an event of default under the 11% Senior Note Agreement, the 11% Senior Note may become immediately due and payable, either automatically or by declaration of holders of more than 50% in principal amount of the 11% Senior Note at the time outstanding.
On July 1, 2016, we entered into an Amended and Restated Note Purchase Agreement (the "Amended and Restated 11% Senior Note Agreement") with GSO to amend and replace the previous note purchase agreement. The Amended and Restated 11% Senior Note Agreement contains customary default provisions, as well as cross-default provisions. In addition, the Amended and Restated 11% Senior Note Agreement required a minimum fixed charge coverage ratio at the end of any fiscal quarter of 1.1 to 1. The Amended and Restated 11% Senior Note Agreement also amended the consolidated leverage ratio covenant, which was further amended in December 2016 (see discussion below). Pursuant to the Amended and Restated 11% Senior Note Agreement, the 11% Senior Note is secured by first-lien security interests in substantially all of our assets and the assets of our subsidiaries. See the above discussion of our Credit Agreement for a description of these security interests. The 11% Senior Note is pari passu in right of payment with all borrowings under the Credit Agreement and rank at least pari passu in right of payment with all other outstanding indebtedness. The Amended and Restated 11% Senior Note Agreement contains customary covenants that limit our ability to, among other things; incur or guarantee additional indebtedness; incur or create liens; merge or consolidate or sell substantially all of our assets; engage in a different business; enter into transactions with affiliates; and make certain payments as set forth in the Amended and Restated 11% Senior Note Agreement. Pursuant to the Amended and Restated 11% Senior Note Agreement, lender fees and other financing costs of
$1.3 million
were deferred, netting against the carrying value of the amount outstanding.
On December 22, 2016, we entered into a First Amendment to Amended and Restated 11% Senior Note Purchase Agreement (the “Amended and Restated 11% Senior Note Agreement Amendment”) with GSO. The Amended and Restated 11% Senior Note Agreement Amendment replaced and modified certain financial covenants in the Amended and Restated 11% Senior Note Agreement by providing that 1) the minimum fixed charge coverage ratio be increased to 1.25 to 1 as of the end of any fiscal quarter; 2) the ratio of consolidated funded indebtedness to EBITDA may not exceed (a) 5.00 to 1 at the end of fiscal quarters ending during the period from and including March 31, 2017 through and including December 31, 2017, (b) 4.75 to 1 at the end of fiscal quarters ending March 31, 2018 and June 30, 2018, (c) 4.50 to 1 at the end of fiscal quarters ending September 30, 2018 and December 31, 2018, and (d) 4.00 to 1 at the end of fiscal quarters ending thereafter. The Amended and Restated 11% Senior Note Agreement Amendment provides that no consolidated leverage ratio is applicable for the fiscal quarter ended December 31, 2016. Pursuant to the Amended and Restated 11% Senior Note Agreement Amendment, lender fees and other financing costs of
$0.4 million
were deferred, netting against the carrying value of the amount outstanding.
At
December 31, 2017
, our consolidated funded indebtedness to EBITDA ratio was
1.66
to 1 (compared to 5.00 to 1 maximum allowed under the Amended and Restated 11% Senior Note Agreement). There is no consolidated funded indebtedness ratio requirement as of
December 31, 2017
as a result of the Amended and Restated 11% Senior Note Agreement. At
December 31, 2017
, our fixed charge coverage ratio was
3.05
to 1 (compared to a 1.25 minimum required under the Amended and Restated 11% Senior Note Agreement).
CCLP Long-Term Debt
CCLP Bank Credit Agreement
.
Under CCLP's credit agreement, as amended (the "CCLP Credit Agreement"), with a syndicate of banks including Bank of America, N.A. as administrative agent, CCLP has an asset-based revolving credit facility with a borrowing capacity of up to
$315 million
, subject to certain requirements, which matures August 4, 2019. The CCLP Credit Agreement is available to provide CCLP's working capital needs, letters of credit, and for general partnership purposes, including capital expenditures and potential future expansions or acquisitions. The CCLP Credit Agreement provides that CCLP can make distributions to holders of its common units, but only if there is no default or event of default under the facility and CCLP maintains excess availability of $30.0 million under the CCLP Credit Agreement. Borrowings under the CCLP Credit Agreement bear interest at a rate per annum equal to, at CCLP's option, either (a) LIBOR (adjusted to reflect any required bank reserves) for an interest period equal to one, two, three, or six months (as selected by CCLP), plus a leverage-based margin that ranges between 2.00% and 3.25% per annum or (b) a base rate plus a leverage-based margin that ranges between 1.00% and 2.25% per annum; such base rate shall be determined by reference to the highest of (1) the prime rate of interest per annum announced from time to time by Bank of America, N.A., (2) the Federal Funds rate plus 0.50% per annum, and (3) LIBOR (adjusted to reflect any required bank reserves) for a one month interest period on such day plus 1.00% per annum. In addition to paying interest on outstanding principal under the CCLP Credit Agreement, CCLP is required to pay a commitment fee ranging from 0.35% to 0.50% per annum in respect of the unutilized commitments. CCLP is also required to pay a customary letter of credit fee equal to the applicable margin on revolving credit LIBOR loans, fronting fees, and other fees, agreed to with the administrative agent and lenders.
Under the CCLP Credit Agreement, CCLP and CSI Compressco Sub Inc. are named as the borrowers, and all obligations under the CCLP Credit Agreement are guaranteed by all of CCLP's existing and future, direct and indirect, domestic restricted subsidiaries (other than domestic subsidiaries that are wholly owned by foreign subsidiaries). We are not a borrower or a guarantor under the CCLP Credit Agreement. The CCLP Credit Agreement includes customary covenants that, among other things, limit CCLP's ability to incur additional debt, incur, or permit certain liens to exist, or make certain loans, investments, acquisitions, or other restricted payments. The CCLP Credit Agreement includes a maximum credit commitment of $315 million and included within the maximum amount is availability for letters of credit (with a sublimit of $20.0 million) and swingline loans (with a sublimit of $60.0 million). The amount of borrowings under the CCLP Credit Agreement is subject to certain limitations, including a borrowing base calculation as described below and borrowing limitations as a result of financial covenants.
On May 25, 2016, CCLP entered into an amendment (the "CCLP Third Amendment") to the CCLP Credit Agreement that, among other things, modified certain financial covenants in the CCLP Credit Agreement. As discussed below, these financial covenants were further amended in November 2016. In addition, the CCLP Third Amendment provided for other changes related to the CCLP Credit Agreement including, among other amendments (i) reducing the maximum aggregate lender commitments from $400.0 million to $340.0 million, (ii) increasing the applicable margin by 0.25% with a range between 2.00% and 3.00% per annum for LIBOR-based loans and 1.00% to 2.00% per annum for base-rate loans, based on the applicable consolidated total leverage ratio, and (iii) imposing a requirement that CCLP uses designated consolidated cash and cash equivalent balances in excess of $35.0 million to prepay the loans. As a result of the reduction of the maximum lender commitment pursuant to the CCLP Third Amendment, unamortized deferred finance costs of
$0.71 million
were charged to interest expense during the year ended December 31, 2016. Pursuant to the CCLP Third Amendment, bank fees of
$0.71 million
were incurred during the year ended December 31, 2016 and were deferred, netting against the carrying value of the amount outstanding under the CCLP Credit Agreement. On
November 3, 2016
, CCLP entered into an additional amendment (the "CCLP Fourth Amendment") to the CCLP Credit Agreement that, among other changes, further modified certain covenants in the CCLP Credit Agreement. The CCLP Fourth Amendment converted the CCLP Credit Agreement from a secured revolving credit facility into an asset-based revolving credit facility ("ABL Facility"). Borrowings under the CCLP Credit Agreement, as amended, may not exceed a borrowing base equal to the sum of (i) 80% of the aggregate net amount of our eligible accounts receivable, plus (ii) 20% of the aggregate value of any eligible parts inventory, in the event we elect to include eligible parts inventory pursuant to a notice to the administrative agent, plus (iii) 80% of the net in-place eligible compressor equipment, decreased each month by the amount of associated depreciation expense, plus (iv) 80% of the cost of new eligible compressor equipment, and minus (v) the amount of any reserves established by the administrative agent in its discretion. In addition, the CCLP Fourth Amendment imposed other requirements, including requirements related to borrowing base reporting on a monthly basis and provisions to permit periodic appraisal and inspection of collateral assets. Pursuant to the CCLP Fourth Amendment, certain additional restrictive provisions ("cash dominion provisions") are imposed if an event of default has occurred and is continuing or excess availability under the ABL Facility falls below $30.0 million. In addition, the CCLP Fourth Amendment reduced the maximum aggregate lender commitments from $340.0 million to $315.0 million. As a result of the further reduction of the aggregate lender commitments pursuant to the CCLP Fourth Amendment, unamortized deferred finance costs of
$0.3 million
were charged to interest expense during the year ended December 31, 2016. Pursuant to the CCLP Fourth Amendment, bank fees of
$0.8 million
were incurred during the year ended December 31, 2016 and were deferred, netting against the carrying value of the amount outstanding under the CCLP Credit Agreement.
On May 5, 2017, CCLP entered into an amendment of the CCLP Credit Agreement (the "CCLP Fifth Amendment") that, among other things, modified certain financial covenants in the CCLP Credit Agreement, providing that
(i) the consolidated total leverage ratio may not exceed (a) 5.95 to 1 as of March 31, 2017; (b) 6.75 to 1 as of June 30, 2017 and September 30, 2017; (c) 6.50 to 1 as of December 31, 2017 and March 31, 2018; (d) 6.25 to 1 as of June 30, 2018 and September 30, 2018; (e) 6.00 to 1 as of December 31, 2018; and (f) 5.75 to 1 as of March 31, 2019 and thereafter; and (ii) the consolidated secured leverage ratio may not exceed 3.25 to 1 as of the end of any fiscal quarter. The consolidated interest coverage ratio was not amended by the CCLP Fifth Amendment. In addition, the CCLP Fifth Amendment (i) increased the applicable margin by 0.25% in the event the consolidated total leverage ratio exceeds 6.00 to 1, resulting in a range for the applicable margin between 2.00% and 3.50% per annum for LIBOR-based loans and between 1.00% and 2.50% per annum for base-rate loans, depending on the consolidated total leverage ratio, and (ii) modified the appraisal delivery requirement from an annual requirement to a semi-annual requirement. In connection with the CCLP Fifth Amendment, the level of CCLP's cash distributions payable on its common units for the quarterly period ended June 30, 2017 will be limited
to the current reduced level. The CCLP Fifth Amendment also included additional revisions that provide flexibility to CCLP for the issuance of preferred securities.
The weighted average interest rate on borrowings outstanding under the CCLP Credit Agreement as of
December 31, 2017
, was
5%
per annum. At
December 31, 2017
, CCLP's consolidated total leverage ratio was
6.48
to 1 (compared to 6.50 to 1 maximum allowed under the CCLP Credit Agreement), its consolidated secured leverage ratio was
2.89
to 1 (compared to 3.25 to 1 maximum allowed under the CCLP Credit Agreement), and its consolidated interest coverage ratio was
2.55
to 1 (compared to a 2.25 to 1 minimum required under the CCLP Credit Agreement). The consolidated total leverage ratio and the consolidated secured leverage ratio, as both are calculated under the CCLP Credit Agreement, exclude the long-term liability for the CCLP Preferred Units in the determination of total indebtedness.
CCLP is in compliance with all covenants of the CCLP Credit Agreement as of
December 31, 2017
. CCLP has reviewed its financial forecasts as of
March 2, 2018
for the subsequent twelve month period, which considers the current level of distributions to be paid on CCLP common units. CCLP believes that it will have adequate liquidity, earnings, and operating cash flows to fund its operations and debt obligations and maintain compliance with the covenants under its debt agreements through March 2, 2019.
CCLP 7.25% Senior Notes.
The obligations under the CCLP 7.25% Senior Notes are jointly and severally, and fully and unconditionally, guaranteed on a senior unsecured basis by each of CCLP’s domestic restricted subsidiaries (other than CSI Compressco Finance) that guarantee CCLP’s other indebtedness (the "Guarantors" and together with the Issuers, the "Obligors"). The CCLP 7.25% Senior Notes and the subsidiary guarantees thereof (together, the "CCLP Securities") were issued pursuant to an indenture described below. As of
December 31, 2017
, $295.9 million in aggregate principal amount of CCLP 7.25% Senior Notes are outstanding.
The Obligors issued the CCLP Securities pursuant to the Indenture dated as of August 4, 2014, (the "Indenture") by and among the Obligors and U.S. Bank National Association, as trustee (the "Trustee"). The CCLP 7.25% Senior Notes accrue interest at a rate of 7.25% per annum. Interest on the CCLP 7.25% Senior Notes is payable semi-annually in arrears on February 15 and August 15 of each year. The CCLP 7.25% Senior Notes are scheduled to mature on August 15, 2022.
The Indenture contains customary covenants restricting CCLP’s ability and the ability of its restricted subsidiaries to: (i) pay dividends and make certain distributions, investments and other restricted payments; (ii) incur additional indebtedness or issue certain preferred shares; (iii) create certain liens; (iv) sell assets; (v) merge, consolidate, sell or otherwise dispose of all or substantially all of its assets; (vi) enter into transactions with affiliates; and (vii) designate its subsidiaries as unrestricted subsidiaries under the Indenture. The Indenture also contains customary events of default and acceleration provisions relating to such events of default, which provide that upon an event of default under the Indenture, the Trustee or the holders of at least 25% in aggregate principal amount of the CCLP 7.25% Senior Notes then outstanding may declare all amounts owing under the CCLP 7.25% Senior Notes to be due and payable.
During September and October 2016, CCLP repurchased on the open market and retired
$54.1 million
aggregate principal amount of its CCLP 7.25% Senior Notes for a purchase price of
$50.9 million
, at an average repurchase price of
94%
of the principal amount of such notes, plus accrued interest, utilizing a portion of the net proceeds from the sale of the CCLP Preferred Units. In connection with the repurchase of these CCLP 7.25% Senior Notes,
$1.4 million
of early extinguishment net gain was credited to other expense during the year ended December 31, 2016, representing the difference between the repurchase price and the
$54.1 million
aggregate principal amount of the CCLP 7.25% Senior Notes repurchased, and
$1.8 million
of remaining unamortized deferred finance costs and discounts associated with the repurchased CCLP 7.25% Senior Notes.
NOTE H
— CCLP SERIES A CONVERTIBLE PREFERRED UNITS
On
August 8, 2016
and
September 20, 2016
, CCLP entered into Series A Preferred Unit Purchase Agreements (the “CCLP Unit Purchase Agreements”) with certain purchasers to issue and sell in private placements (the "Initial Private Placement" and "Subsequent Private Placement," respectively) an aggregate of
6,999,126
of CCLP Preferred Units for a cash purchase price of
$11.43
per CCLP Preferred Unit (the “Issue Price”), resulting in total 2016 net proceeds to CCLP, after deducting certain offering expenses, of
$77.3 million
. We purchased
874,891
of the CCLP Preferred Units in the Initial Private Placement at the aggregate Issue Price of
$10.0 million
.
We and the other holders of CCLP Preferred Units (each, a “CCLP Preferred Unitholder”) will receive quarterly distributions, which are paid in kind in additional CCLP Preferred Units, equal to an annual rate of
11.00%
of the Issue Price (
$1.2573
per unit annualized), subject to certain adjustments. The rights of the CCLP Preferred Units include certain anti-dilution adjustments, including adjustments for economic dilution resulting from the issuance of CCLP common units in the future below a set price.
A ratable portion of the CCLP Preferred Units have been, and will continue to be, converted into CCLP common units on the eighth day of each month over a period of thirty months that began in March 2017 (each, a “Conversion Date”), subject to certain provisions of the Amended and Restated CCLP Partnership Agreement that may delay or accelerate all or a portion of such monthly conversions. On each Conversion Date, a portion of the CCLP Preferred Units will convert into CCLP common units representing limited partner interests in CCLP in an amount equal to, with respect to each CCLP Preferred Unitholder, the number of CCLP Preferred Units held by such CCLP Preferred Unitholder divided by the number of Conversion Dates remaining, subject to adjustment described in the Amended and Restated CCLP Partnership Agreement, with the conversion price (the "Conversion Price") determined by the trading prices of the common units over the prior month, among other factors, and as otherwise impacted by the existence of certain conditions related to the CCLP common units. On June, 7, 2017, as permitted under the Amended and Restated CCLP Partnership Agreement, CCLP elected to defer the monthly conversion of CCLP Preferred Units for each of the Conversion Dates during the three month period beginning July 8, 2017. As a result,
no
CCLP Preferred Units were converted into CCLP common units during the three month period ended September 30, 2017, and future monthly conversions were increased beginning in October 2017. Based on the number of Preferred Units outstanding as of
December 31, 2017
, the maximum aggregate number of CCLP common units that could be required to be issued pursuant to the conversion provisions of the CCLP Preferred Units is approximately
34.1 million
CCLP common units; however, CCLP may, at its option, pay cash, or a combination of cash and common units, to the CCLP Preferred Unitholders instead of issuing common units on any Conversion Date, subject to certain restrictions as described in the Amended and Restated CCLP Partnership Agreement and the CCLP Credit Agreement. The total number of CCLP Preferred Units outstanding as of
December 31, 2017
was
5,975,200
, of which we held
750,417
.
Because the CCLP Preferred Units may be settled using a variable number of CCLP common units, the fair value of the CCLP Preferred Units, net of the units we purchased, is classified as long-term liabilities on our consolidated balance sheet in accordance with ASC 480 "Distinguishing Liabilities and Equity." The fair value of the CCLP Preferred Units as of
December 31, 2017
was
$61.4 million
. Changes in the fair value during each quarterly period, including the
$3.0 million
net decrease and
$4.4 million
net increase in fair value during 2017 and 2016, respectively, are charged or credited to earnings in the accompanying consolidated statements of operations. Based on the conversion provisions of the CCLP Preferred Units, and using the Conversion Price calculated as of
December 31, 2017
, the theoretical number of CCLP common units that would be issued if all of the outstanding CCLP Preferred Units were converted on
December 31, 2017
on the same basis as the monthly conversions would be approximately
14.6 million
CCLP common units, with an aggregate market value of
$79.9 million
. A $1 decrease in the Conversion Price would result in the issuance of
3.8 million
additional CCLP common units pursuant to these conversion provisions.
NOTE I
— DECOMMISSIONING AND OTHER ASSET RETIREMENT OBLIGATIONS
The large majority of our asset retirement obligations as of December 31, 2016 and 2017 consists of the remaining future well abandonment and decommissioning costs for offshore oil and gas properties and platforms owned by our Maritech subsidiary, including the decommissioning and debris removal costs associated with its remaining offshore platforms previously destroyed by hurricanes. As part of the sale of our Offshore Division in March 2018, Orinoco assumed all of the liabilities and obligations currently associated with Maritech, including but not limited to all currently identified and any future identified asset retirement obligations. The amount of decommissioning liabilities recorded by Maritech is reduced by amounts allocable to joint interest owners in these properties and platforms.
We also operate facilities in various U.S. and foreign locations that are used in the manufacture, storage, and sale of our products, inventories, and equipment. These facilities are a combination of owned and leased assets. The values of these asset retirement obligations for non-Maritech properties were approximately
$11.7 million
and
$9.4 million
as of
December 31, 2017
and
2016
, respectively. We are required to take certain actions in connection with the retirement of these assets. We have reviewed our obligations in this regard in detail and estimated the cost of these actions. The original estimates are the fair values that have been recorded for retiring
these long-lived assets. The associated asset retirement costs are capitalized as part of the carrying amount of these long-lived assets. The costs for non-oil and gas assets are depreciated on a straight-line basis over the lives of those assets.
The changes in the values of our asset retirement obligations during the most recent two year period are
as follows:
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
|
(In Thousands)
|
Beginning balance for the period, as reported
|
|
$
|
55,478
|
|
|
$
|
57,449
|
|
Activity in the period:
|
|
|
|
|
|
|
Accretion of liability
|
|
2,051
|
|
|
2,249
|
|
Retirement obligations incurred
|
|
265
|
|
|
—
|
|
Revisions in estimated cash flows
|
|
1,180
|
|
|
(180
|
)
|
Settlement of retirement obligations
|
|
(572
|
)
|
|
(4,040
|
)
|
Ending balance
|
|
$
|
58,402
|
|
|
$
|
55,478
|
|
We review the adequacy of our decommissioning liabilities whenever indicators suggest that the estimated cash flows underlying the liabilities have changed.
Asset retirement obligations are recorded in accordance with FASB ASC 410, whereby the estimated fair value of a liability for asset retirement obligations is recorded in the period in which it is incurred and in which a reasonable estimate can be made. Such estimates are based on relevant assumptions that we believe are reasonable. The cost estimates for Maritech asset retirement obligations are considered reasonable estimates consistent with current market conditions, and we believe reflect the amount of work legally obligated to be performed in accordance with Bureau of Safety and Environmental Enforcement ("BSEE") standards, as revised from time to time.
The amount of work performed or estimated to be performed on a Maritech property asset retirement obligation may often exceed amounts previously estimated for numerous reasons. Property conditions encountered, including subsea, geological, or downhole conditions, may be different from those anticipated at the time of estimation due to the age of the property and the quality of information available about the particular property conditions. Maritech’s remaining oil and gas properties and production platforms were drilled and constructed by other operators many years ago, and frequently there is not a great deal of detailed documentation on which to base the estimated asset retirement obligation for these properties. Appropriate underwater surveys are performed to determine the condition of such properties as part of our due diligence in estimating the costs, but not all conditions have been able to be determined prior to the commencement of the actual work.
Maritech has one remaining property that was damaged by hurricanes in the past, leaving the production platform toppled on the seabed and production tubing from the wells (which may be under high pressure) bent under the water. While the basic procedures involved in the plugging and abandonment of wells and decommissioning of platforms and pipelines and removal of debris is generally similar for these properties, the cost of performing work at these damaged locations is particularly difficult to estimate due to the unique conditions encountered, including the uncertainty regarding the extent of physical damage to many of the structures. Our estimate of
remaining
hurricane related decommissioning costs for this one remaining toppled platform is
approximately
$8.2 million
and has been accrued as part of Maritech’s decommissioning liabilities as of
December 31, 2017
.
During the performance of asset retirement activities, unforeseen weather or other conditions may extend the duration and increase the cost of the projects, which are normally not done on a fixed price basis, thereby resulting in costs in excess of the original estimate.
In addition, Maritech has encountered situations where previously plugged and abandoned wells on its properties have later exhibited a buildup of pressure, which is evidenced by gas bubbles coming from the plugged well head. We refer to this situation as “wells under pressure” and this can either be discovered when performing additional work at the property or by notification from a third party. Wells under pressure require Maritech to return to the site to perform additional plug and abandonment procedures that were not originally anticipated and included in the estimate of the asset retirement obligation for such property. Remediation work at previously abandoned well
sites is particularly costly, due to the lack of a platform from which to base these activities. Maritech is the last operator of record for its plugged wells, and, as Maritech's parent company, we and Maritech bear the risk of additional future work required as a result of wells becoming pressurized in the future.
For oil and gas properties previously operated by Maritech, the purchaser of the properties generally became the successor operator and assumed the financial responsibilities associated with the properties’ operations and abandonment and decommissioning. However, to the extent that purchasers of these oil and gas properties fail to perform the abandonment and decommissioning work required and there is insufficient bonding or other security, the previous owners and operators of the properties, including Maritech and us as Maritech's parent company, may be required to assume responsibility for the abandonment and decommissioning obligations.
NOTE J
— COMMITMENTS AND CONTINGENCIES
Litigation
We are named defendants in several lawsuits and respondents in certain governmental proceedings arising in the ordinary course of business. While the outcome of lawsuits or other proceedings against us cannot be predicted with certainty, management does not consider it reasonably possible that a loss resulting from such lawsuits or other proceedings in excess of any amounts accrued has been incurred that is expected to have a material adverse impact on our financial condition, results of operations, or liquidity.
On March 18, 2011, we filed a lawsuit in the Circuit Court of Union County, Arkansas, asserting claims of professional negligence, breach of contract and other claims against the engineering firm we hired for engineering design, equipment, procurement, advisory, testing and startup services for our El Dorado, Arkansas chemical production facility. The engineering firm disputed our claims and promptly filed a motion to compel the matter to arbitration. After a lengthy procedural dispute in Arkansas state court, arbitration proceedings were initiated on November 15, 2013. Ultimately, on December 16, 2016, the arbitration panel ruled in our favor, declared us as the prevailing party, and awarded us a total net amount of
$12.8 million
. We received full payment of the
$12.8 million
final award on January 5, 2017, and this amount was credited to earnings during the first quarter of 2017.
From May 2009 to December 2014, EPIC Diving & Marine Services, LLC (“EPIC”), a wholly-owned subsidiary, was the charterer of a dive support vessel from a service provider. At the time of redelivery of the vessel there was a dispute between EPIC and the service provider that was submitted to arbitration in London pursuant to the dispute resolution provision of the charter agreement. Just prior to the scheduled arbitration proceedings in June 2017, EPIC reached a favorable settlement in relation to certain of the service provider's claims against EPIC. EPIC’s dispute with the service provider that a fee was due at the time of redelivery of the vessel proceeded to arbitration on June 20, 2017. On July 6, 2017, the arbitration panel issued its ruling against EPIC, awarding the service provider
$3.0 million
, plus interest and fees. A net exposure of
$2.8 million
was accrued and charged to earnings during 2017.
Environmental
One of our subsidiaries, TETRA Micronutrients, Inc. (TMI), previously owned and operated a production facility located in Fairbury, Nebraska. TMI is subject to an Administrative Order on Consent issued to American Microtrace, Inc. (n/k/a/ TETRA Micronutrients, Inc.) in the proceeding styled
In the Matter of American Microtrace Corporation
, EPA I.D. No. NED00610550, Respondent, Docket No. VII-98-H-0016, dated September 25, 1998 (the "Consent Order"), with regard to the Fairbury facility. TMI is liable for ongoing environmental monitoring at the Fairbury facility under the Consent Order; however, the current owner of the Fairbury facility is responsible for costs associated with the closure of that facility. While the outcome cannot be predicted with certainty, management does not consider it reasonably possible that a loss in excess of any amounts accrued has been incurred or is expected to have a material adverse impact on our financial condition, results of operations, or liquidity.
Product Purchase Obligations
In the normal course of our Fluids Division operations, we enter into supply agreements with certain manufacturers of various raw materials and finished products. Some of these agreements have terms and conditions that specify a minimum or maximum level of purchases over the term of the agreement. Other agreements require us to purchase the entire output of the raw material or finished product produced by the manufacturer. Our purchase obligations under these agreements apply only with regard to raw materials and
finished products that meet specifications set forth in the agreements. We recognize a liability for the purchase of such products at the time we receive them. As of
December 31, 2017
, the aggregate amount of the fixed and determinable portion of the purchase obligation pursuant to our Fluids Division’s supply agreements was
approximately
$113.4 million
, including
$9.5 million
during
2018
,
$9.5 million
during
2019
,
$9.5 million
during
2020
,
$9.5 million
during
2021
,
$9.5 million
during
2022
, and
$66.2 million
thereafter, extending through 2029. Amounts purchased under these agreements for each of the years ended
December 31, 2017
,
2016
,
and
2015
,
was
$16.1 million
,
$13.3 million
, and
$22.0 million
, respectively.
Other Contingencies
During 2011, in connection with the sale of a significant majority of Maritech's oil and gas producing properties, the buyers of the properties assumed the associated decommissioning liabilities pursuant to the purchase and sale agreements. In March 2018, we closed the Maritech Asset Purchase Agreement with Orinoco that provided for the purchase by Orinoco of the Maritech Properties. Also in March 2018, we finalized the Maritech Equity Purchase Agreement with Orinoco, that provided for the purchase by Orinoco of the Maritech Equity Interests. As a result of these transactions, we have effectively exited the businesses of our Offshore Services and Maritech segments and Orinoco assumed all of Maritech's remaining abandonment and decommissioning obligations, For those oil and gas properties Maritech previously operated, the buyers of the properties assumed the financial responsibilities associated with the properties' operations, including abandonment and decommissioning, and generally became the successor operator. Some buyers of these Maritech properties subsequently sold certain of these properties to other buyers who also assumed these financial responsibilities associated with the properties' operations, and these buyers also typically became the successor operator of the properties. To the extent that a buyer of these properties fails to perform the abandonment and decommissioning work required, the previous owner, including Maritech, may be required to perform the abandonment and decommissioning obligation. A significant portion of the decommissioning liabilities that were assumed by the buyers of the Maritech properties in 2011 remains unperformed, and we believe the amounts of these remaining liabilities are significant. We monitor the financial condition of the buyers of these properties from Maritech, and if oil and natural gas pricing levels deteriorate, we expect that one or more of these buyers may be unable to perform the decommissioning work required on the properties acquired from Maritech.
Certain oil and gas producing companies that bought Maritech properties are currently experiencing severe financial difficulties. With regard to certain of these properties, Maritech has security in the form of bonds or cash escrows intended to secure the buyers' obligations to perform the decommissioning work. One company that bought, and subsequently sold, Maritech properties filed for Chapter 11 bankruptcy protection in August 2015. Maritech and its legal counsel continue to monitor the status of these companies. As of
December 31, 2017
, we do not consider the likelihood of Maritech becoming liable for decommissioning liabilities on sold properties to be probable.
NOTE K
— CAPITAL STOCK AND WARRANTS
Our Restated Certificate of Incorporation, as amended during 2017, authorizes us to issue
250,000,000
shares of common stock, par value
$.01
per share, and
5,000,000
shares of preferred stock, par value
$.01
per share. As of
December 31, 2017
, we had
115,877,704
shares of common stock outstanding, with
2,638,093
shares held in treasury, and no shares of preferred stock outstanding. The voting, dividend, and liquidation rights of the holders of common stock are subject to the rights of the holders of preferred stock. The holders of common stock are entitled to one vote for each share held. There is no cumulative voting. Dividends may be declared and paid on common stock as determined by our Board of Directors, subject to any preferential dividend rights of any then outstanding preferred stock.
Issuances of Common Stock.
On June 21, 2016, we completed an underwritten public offering of
11.5 million
shares of our common stock, which included
1.5 million
shares of common stock pursuant to an option granted to the underwriters to purchase additional shares, at a price to the public of
$5.50
per share (
$5.2525
per share net of underwriting discounts). We utilized the net offering proceeds of
$60.2 million
to repay the remaining balance outstanding of certain senior secured notes, to reduce the balance outstanding under our Credit Agreement, to pay offering related discounts and expenses, and for general corporate purposes. The offering was made pursuant to a shelf registration statement filed with the Securities and Exchange Commission on March 23, 2016.
On December 14, 2016, we completed a firm commitment underwritten offering of
22.3 million
shares of our common stock at a price to the public of
$5.15
per share (
$4.9183
per share net of underwriting discounts) and the Warrants to purchase
11.2 million
shares of our common stock at an exercise price of
$5.75
per share prior to the 60-month expiration date of the Warrants. The
22.3 million
shares of our common stock issued and the Warrants to purchase
11.2 million
shares of our common stock includes
2.9 million
shares of our common stock and Warrants to acquire an additional
1.5 million
shares of our common stock related to the exercise of an option granted to the underwriters. We utilized the net offering proceeds of
$109.7 million
to repay outstanding indebtedness and other offering expenses. As of
December 31, 2017
, all of the Warrants remain outstanding.
The Warrants were issued pursuant to a Warrant Agreement, dated December 14, 2016, and are exercisable immediately upon issuance and from time to time thereafter through and including the fifth year anniversary of the initial issuance date. At the request of a holder following a change of control, we or the successor entity will exchange such Warrant for consideration in accordance with a Black Scholes option pricing model in the form of, at our election, Rights (as defined in the Warrant Agreement) or cash. Similarly, within a period of time prior to the consummation of a change of control, we have the right to redeem all of the Warrants for cash in an amount determined in accordance with a Black-Scholes option pricing model.
The Warrants are accounted for as a derivative liability in accordance with ASC 815 "Derivatives and Hedging" and accordingly are carried at their fair value, with changes in fair value included in Other Expense in the period of change. As of
December 31, 2017
and
2016
, the fair value of the Warrants was
$13.2 million
and
$18.5 million
, respectively. Changes in fair value during the year, included a
$5.3 million
change in fair value was credited to earnings during 2017 and a
$2.1 million
change in fair value charged to earnings during 2016. In connection with the Warrants, approximately
$0.9 million
of the
$6.5 million
total issuance costs, including underwriting discounts, associated with the December 2016 offering was charged to earnings.
A summary of the activity of our common shares outstanding and treasury shares held for the three year period ending
December 31, 2017
, is as follows:
|
|
|
|
|
|
|
|
|
|
|
Common Shares Outstanding
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
At beginning of period
|
|
114,985,072
|
|
|
80,256,544
|
|
|
79,649,946
|
|
Exercise of common stock options, net
|
|
—
|
|
|
636,937
|
|
|
67,808
|
|
Grants of restricted stock, net
|
|
892,632
|
|
|
281,591
|
|
|
538,790
|
|
Issuance of common stock
|
|
—
|
|
|
33,810,000
|
|
|
—
|
|
At end of period
|
|
115,877,704
|
|
|
114,985,072
|
|
|
80,256,544
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury Shares Held
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
At beginning of period
|
|
2,536,421
|
|
|
2,281,495
|
|
|
2,224,285
|
|
Shares received upon exercise of common stock options
|
|
—
|
|
|
13,854
|
|
|
36,818
|
|
Shares received upon vesting of restricted stock, net
|
|
101,672
|
|
|
241,072
|
|
|
20,392
|
|
At end of period
|
|
2,638,093
|
|
|
2,536,421
|
|
|
2,281,495
|
|
Our Board of Directors is empowered, without approval of the stockholders, to cause shares of preferred stock to be issued in one or more series and to establish the number of shares to be included in each such series and the rights, powers, preferences, and limitations of each series. Because the Board of Directors has the power to establish the preferences and rights of each series, it may afford the holders of any series of preferred stock preferences, powers and rights, voting or otherwise, senior to the rights of holders of common stock. The issuance of the preferred stock could have the effect of delaying or preventing a change in control of the Company.
Upon our dissolution or liquidation, whether voluntary or involuntary, holders of our common stock will be entitled to receive all of our assets available for distribution to our stockholders, subject to any preferential rights of any then outstanding preferred stock.
In January 2004, our Board of Directors authorized the repurchase of up to
$20.0 million
of our common stock. During the three years ending
December 31, 2017
, we
made no purchases of our common
stock pursuant to this authorization.
NOTE L
— EQUITY-BASED COMPENSATION
We have various equity incentive compensation plans which provide for the granting of restricted common stock, options for the purchase of our common stock, and other performance-based, equity-based compensation awards to our executive officers, key employees, nonexecutive officers, consultants, and directors. Stock options are exercisable for periods
of
up to ten years. Compensation cost for all share-based payments is based on the grant date fair value and is recognized in earnings over the requisite service period. Total equity-based compensation expense, before tax, for the three years ended
December 31, 2017
,
2016
, and
2015
, was
$7.8 million
,
$13.7 million
, and
$16.9 million
, respectively, and is included in general and administrative expense. Total equity-based compensation expense, net of taxes,
for the three years ended
December 31, 2017
,
2016
, and
2015
,
was
$5.0 million
,
$9.5 million
, and
$13.9 million
, respectively. During 2015, we automated the computation of equity-based compensation expense, converting from a manual calculation of the overall impact of forfeitures and vesting on the amount of expense. As a result of this conversion, and performing a retroactive review of equity-based compensation expense for all periods from 2006 to 2015, we recorded a correcting pre-tax adjustment of $
6.7 million
during the fourth quarter of 2015. Management does not consider the impact of this cumulative adjustment to be material to any individual annual period.
Stock Incentive Plans
The TETRA Technologies, Inc. 1990 Stock Option Plan (the "1990 Plan") was initially adopted in 1985 and subsequently amended to change the name, the number, and the type of options that could be granted, as well as the time period for granting stock options. As of December 31, 2004, no further options may be granted under the 1990 Plan. We granted performance stock options under the 1990 Plan to certain executive officers. These granted options have an exercise price per share of not less than the market value at the date of issuance and are fully vested and exercisable.
During 1996, we adopted the 1996 Stock Option Plan for Nonexecutive Employees and Consultants (the "Nonqualified Plan") to enable us to award nonqualified stock options to nonexecutive employees and consultants who are key to our performance.
As of May 2, 2006, no further options may be granted under the Nonqualified Plan.
In May 2006, our stockholders approved the adoption of the TETRA Technologies, Inc. 2006 Equity Incentive Compensation Plan. Pursuant to the TETRA Technologies, Inc. 2006 Equity Incentive Compensation Plan, we were authorized to grant up to
1,300,000
shares in the form of stock options (including incentive stock options and nonqualified stock options); restricted stock; bonus stock; stock appreciation rights; and performance awards to employees, consultants, and non-employee directors. As a result of the May 2006 adoption and approval of the TETRA Technologies, Inc. 2006 Equity Incentive Compensation Plan, no further awards may be granted under our other previously existing plans. As of May 4, 2008, no further awards may be granted under the TETRA Technologies, Inc. 2006 Equity Incentive Compensation Plan.
In May 2007, our stockholders approved the adoption of the TETRA Technologies, Inc. 2007 Equity Incentive Compensation Plan. In May 2008, our stockholders approved the adoption of the TETRA Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation Plan, which among other changes, resulted in an increase in the maximum number of shares authorized for issuance. In May 2010, our stockholders approved further amendments to the TETRA Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation Plan (renamed as the 2007 Long Term Incentive Compensation Plan) which, among other changes, resulted in an additional increase in the maximum number of shares authorized for issuance. Pursuant to the 2007 Long Term Incentive Compensation Plan, we are authorized to grant up to
5,590,000
shares in the form of stock options (including incentive stock options and nonqualified stock options); restricted stock; bonus stock; stock appreciation rights; and performance awards to employees, consultants, and non-employee directors.
In May 2011, our stockholders approved the adoption of the TETRA Technologies, Inc. 2011 Long Term Incentive Compensation Plan. Pursuant to this plan, we were authorized to grant up to
2,200,000
shares in the form of stock options, restricted stock, bonus stock, stock appreciation rights, and performance awards to employees, consultants, and non-employee directors. On May 3, 2013, shareholders approved the TETRA Technologies, Inc.
2011 Long Term Incentive Compensation Plan which, among other things, increased the number of authorized shares to
5,600,000
.
In June 2011, the Compressco Partners, L.P. 2011 Long Term Incentive Plan ("CCLP Long Term Incentive Plan") was adopted by the board of directors of CCLP’s general partner. The CCLP Long Term Incentive Plan provides for grants of restricted units, phantom units, unit awards and other unit-based awards up to a plan maximum of
1,537,122
common units.
On May 3, 2016, shareholders approved the TETRA Technologies, Inc. Third Amended and Restated 2011 Long Term Incentive Compensation Plan which, among other things, increased the number of authorized shares to
11,000,000
.
Grants of Equity Awards by CCLP
During each of the three years ended
December 31, 2017
, CCLP granted restricted unit, phantom unit, or performance phantom unit awards to certain employees, officers, and directors of its general partner or of our employees. Awards of restricted units and phantom units generally vest over a three year period. Awards of performance phantom units cliff vest at the end of a performance period and are settled based on achievement of related performance measures over the performance period. Phantom units are notional units that entitle the grantee to receive a common unit upon the vesting of the award. Each of the phantom unit and performance phantom unit awards includes distribution equivalent rights that enable the recipient to receive additional units equal in value to the accumulated cash distributions made on the units subject to the award from the date of grant. Accumulated distributions associated with each underlying unit are payable upon settlement of the related phantom unit award (and are forfeited if the related award is forfeited).
The following is a summary
of CCLP’s
equity award
activity for the year ended
December 31, 2017
:
|
|
|
|
|
|
|
|
|
|
|
Units
|
|
Weighted Average
Grant Date Fair
Value Per Unit
|
|
|
(In Thousands)
|
|
|
Nonvested units outstanding at December 31, 2016
|
|
609
|
|
|
$
|
13.41
|
|
Units granted
(1)
|
|
290
|
|
|
8.40
|
|
Units cancelled
|
|
(173
|
)
|
|
16.11
|
|
Units vested
|
|
(257
|
)
|
|
13.17
|
|
Nonvested units outstanding at December 31, 2017
(2)
|
|
469
|
|
|
$
|
9.31
|
|
|
|
(1)
|
The number excludes
289,830
performance-based phantom units, which represents the additional number of common units that would be issued if the maximum level of performance under the awards is achieved.
|
(2) The number of units granted shown above excludes
176,159
performance-based phantom units, which, when combined with the
18,226
granted (net of 2017 forfeitures), represents the maximum number of common units that would be issued if the maximum level of performance under the awards is achieved. The number of units actually issued under the awards may range from zero to
352,318
.
Stock Options
The weighted average fair value of options granted during the years ended
December 31, 2017
,
2016
, and
2015
,
was
$2.01
,
$3.16
, and
$3.17
, respectively, using the Black-Scholes option valuation model with the following weighted average assumptions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
Expected stock price volatility
|
|
53%
|
|
|
52%
|
|
|
49% to 51%
|
|
Expected life of options
|
|
4.5 years
|
|
|
4.6 years
|
|
|
4.6 years
|
|
Risk free interest rate
|
|
1.8%
|
|
|
1.2%
|
|
|
1.41% to 1.51%
|
|
Expected dividend yield
|
|
—
|
|
|
—
|
|
|
—
|
|
The risk-free interest rate is based on the U.S. Treasury yield curve in effect on the grant date for a period commensurate with the estimated expected life of the stock options. Expected volatility is based on the historical
volatility of our stock over the period commensurate with the expected life of the stock options and other factors. The dividend yield is based on the current annualized dividend rate in effect during the quarter in which the grant was made. At the time of the stock option grants during each of the years ended
December 31, 2017
,
2016
and
2015
, we had not historically paid any dividends and did not expect to pay any dividends during the expected life of the stock options.
The following is a summary of stock option activity for the year ended
December 31, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares Under Option
|
|
Weighted Average
Option Price
Per Share
|
|
Weighted-Average Remaining Contractual Life
|
|
Aggregate Intrinsic Value
(in thousands)
|
|
|
(In Thousands)
|
|
|
|
|
|
|
Outstanding at January 1, 2017
|
|
4,387
|
|
|
$
|
9.81
|
|
|
|
|
|
Options granted
|
|
1,486
|
|
|
4.46
|
|
|
|
|
|
Options cancelled
|
|
(646
|
)
|
|
7.34
|
|
|
|
|
|
Options exercised
|
|
—
|
|
|
—
|
|
|
|
|
|
Options expired
|
|
(10
|
)
|
|
$
|
14.02
|
|
|
|
|
|
Outstanding at December 31, 2017
|
|
5,217
|
|
|
$
|
8.59
|
|
|
5.7
|
|
$
|
308
|
|
Expected to vest at December 31, 2017
|
|
5,217
|
|
|
$
|
8.59
|
|
|
5.7
|
|
$
|
308
|
|
Exercisable at December 31, 2017
|
|
3,642
|
|
|
$
|
10.07
|
|
|
4.4
|
|
$
|
239
|
|
Intrinsic value is the difference between the market value of our stock option multiplied by the number of stock options outstanding for those stock options where the market value exceeds their exercise price. The total intrinsic value of stock options exercised during
December 31, 2017
,
2016
, and
2015
,
was
approximately
$0.0 million
,
$0.1 million
,
and
$0.2 million
, respectively.
At
December 31, 2017
, total unrecognized compensation cost related to unvested stock options of
$2.9 million
, is expected to be recognized over a weighted-average remaining service period of
1.60
years.
Restricted Stock
Restricted stock awards are periodically granted to key employees, including grants for employment inducements, as well as to members of our Board of Directors. Employee awards provide for vesting periods ranging from three to five years. Non-employee director grants vest in full before the first anniversary of the grant. Upon vesting of these grants, shares are issued to award recipients. The following is a summary of activity for our outstanding restricted stock awards for the year ended
December 31, 2017
:
|
|
|
|
|
|
|
|
|
|
|
Shares
|
|
Weighted Average
Grant Date Fair
Value Per Share
|
|
|
(In Thousands)
|
|
|
Nonvested restricted shares outstanding at December 31, 2016
|
|
805
|
|
|
$
|
7.60
|
|
Granted
|
|
1,146
|
|
|
4.18
|
|
Vested
|
|
(780
|
)
|
|
6.33
|
|
Cancelled/Forfeited
|
|
(135
|
)
|
|
5.41
|
|
Nonvested restricted shares outstanding at December 31, 2017
|
|
1,036
|
|
|
$
|
5.06
|
|
Total compensation cost recognized for restricted stock awards was
$4.0 million
,
$8.4 million
, and
$5.4 million
for the years ended
December 31, 2017
,
2016
, and
2015
, respectively. Total unrecognized compensation cost at
December 31, 2017
, related to restricted stock awards is approximately
$3.9 million
which is expected to be recognized over a weighted-average remaining amortization period of
1.75
years. During the years ended
December 31, 2017
,
2016
, and
2015
, the total fair value of shares vested was
$4.8 million
,
$8.4 million
and
$4.8 million
, respectively.
During
2017
,
2016
, and
2015
, we
received
101,669
,
254,858
and
57,336
shares, respectively, of our common stock related to the vesting of certain employee restricted stock. Such surrendered shares received by us are included in treasury stock.
At
December 31, 2017
, net of options previously exercised pursuant to our various
equity compensation
plans, we have a maximum of
3,646,152
shares of common stock issuable pursuant to
awards
previously granted and outstanding and
awards
authorized to be granted in the future.
Cash-Settled Stock Appreciation Rights
During the third quarter of 2017, we issued a stand-alone, cash-settled stock appreciation rights ("SAR") award to an executive officer. This award is valued by using the Black Scholes option valuation model and such fair value is recognized based on the portion of the requisite service period satisfied as of each valuation date. The fair valuation of the stock appreciation rights liability is increased by, among other factors, increases in our common stock price, and by increases in the volatility of our common stock price. This stock appreciation rights award is reflected as an accrued liability in our consolidated balance sheet. Increases (or decreases) in the fair value of the stock appreciation rights award will increase (decrease) the associated liability and result in future adjustments to earnings for the associated valuation losses (gains).
The following table presents the
2017
changes in our outstanding SARs and the associated weighted average exercise price:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of SARs
|
|
Weighted Average Fair Value
|
|
Weighted Average Exercise Price
|
|
|
(In Thousands)
|
|
|
|
|
Outstanding at December 31, 2016
|
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Granted
|
|
134
|
|
|
2.94
|
|
|
4.51
|
|
Exercised
|
|
—
|
|
|
—
|
|
|
—
|
|
Forfeited
|
|
—
|
|
|
—
|
|
|
—
|
|
Outstanding at December 31, 2017
|
|
134
|
|
|
$
|
2.94
|
|
|
$
|
4.51
|
|
We recognized compensation expense associated with our outstanding SARs of
$0.1 million
in 2017. Outstanding SARs had total intrinsic values of
$0.0 million
at year-end
2017
.
We used the following assumptions to determine the fair value of the SARs granted in 2017:
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
Expected stock price volatility
|
|
63.2
|
%
|
Expected life of SARs
|
|
9.1 years
|
|
Risk free interest rate
|
|
2.37
|
%
|
Expected dividend yield
|
|
—
|
|
NOTE M
— 401(k) PLAN
We have a 401(k) retirement plan (the "Plan") that covers substantially all employees and entitles them to contribute up to
70%
of their annual compensation, subject to maximum limitations imposed by the Internal Revenue Code. We have historically matched
50%
of each employee’s contribution up to
6%
of annual compensation, subject to certain limitations as outlined in the Plan. Beginning in May 2016, we suspended the matching of employee contributions for an indefinite period. In August 2017, the matching of employee contributions was reinstated. In addition, we can make discretionary contributions which are allocable to participants in accordance with the Plan. Total expense related to our 401(k) plan
was
$0.9 million
,
$1.4 million
, and
$4.2 million
in
2017
,
2016
, and
2015
, respectively.
NOTE N
— DEFERRED COMPENSATION PLAN
We provide our officers, directors, and certain key employees with the opportunity to participate in an unfunded, deferred compensation program.
There were
twenty-five
participants in the program at
December 31, 2017
. Under the program, participants may defer up to 100% of their yearly total cash compensation. The amounts deferred remain our sole property, and we use a portion of the proceeds to purchase life insurance policies on the lives of certain of the participants. The insurance policies, which also remain our sole property, are payable to us upon the death of the insured. We separately contract with the participant to pay to the participant the amount of deferred compensation, as adjusted for gains or losses, invested in participant-selected investment funds. Participants may elect to receive deferrals and earnings at termination, death, or at a specified future date while still employed. Distributions while
employed must be at least three years after the deferral election. The program is not qualified under Section 401 of the Internal Revenue Code. At
December 31, 2017
, the amounts payable under the plan approximated the value of the corresponding assets we owned.
NOTE O
— MARKET RISKS AND DERIVATIVE AND HEDGE CONTRACTS
We are exposed to financial and market risks that affect our businesses. We have concentrations of credit risk as a result of trade receivables owed to us by companies in the energy industry. We have currency exchange rate risk exposure related to transactions denominated in a foreign currency as well as to investments in certain of our international operations. As a result of our variable rate bank credit facilities,
including the variable rate credit facility of CCLP, we face market risk exposure related to changes in applicable interest rates. Our financial risk management activities may at times involve, among other measures, the use of derivative financial instruments, such as swap and collar agreements, to hedge the impact of market price risk exposures.
Derivative Contracts
Stock Warrants
. In December 2016, we issued the Warrants in connection with an offering of our common stock. The warrants are exercisable into shares of our common stock at an exercise price of
$5.75
per share. The fair value of the Warrants are calculated using the Black-Scholes valuation model, and totaled
$13.2 million
as of
December 31, 2017
, and is classified as Warrant Liability, a long-term liability, on the consolidated balance sheet. Warrant fair value (gains) and losses during
2017
and
2016
was
$(5.3) million
and
$2.1 million
, respectively, charged to Warrants fair value adjustment, in the accompanying consolidated statement of operations.
Foreign Currency Derivative Contracts
.
We and CCLP enter into 30-day foreign currency forward derivative contracts as part of a program designed to mitigate the currency exchange rate risk exposure on selected transactions of certain foreign subsidiaries. As of
December 31, 2017
, we and CCLP had the following foreign currency derivative contracts outstanding relating to a portion of our foreign operations:
|
|
|
|
|
|
|
|
|
|
|
Derivative Contracts
|
|
U.S. Dollar Notional Amount
|
|
Traded Exchange Rate
|
|
Settlement Date
|
|
|
(In Thousands)
|
|
|
|
|
Forward purchase euro
|
|
$
|
1,743
|
|
|
1.19
|
|
|
1/18/2018
|
Forward purchase pounds sterling
|
|
$
|
5,998
|
|
|
1.33
|
|
|
1/18/2018
|
Forward sale Canadian dollar
|
|
$
|
3,756
|
|
|
1.29
|
|
1/18/2018
|
Forward purchase Mexican peso
|
|
$
|
6,974
|
|
|
19.28
|
|
|
1/18/2018
|
Forward sale Norwegian krone
|
|
$
|
4,131
|
|
|
8.40
|
|
|
1/18/2018
|
Forward sale Mexican peso
|
|
$
|
6,067
|
|
|
19.28
|
|
1/18/2018
|
As of
December 31, 2016
, we and CCLP had the following foreign currency derivative contracts outstanding relating to a portion of our foreign operations:
|
|
|
|
|
|
|
|
|
|
Derivative Contracts
|
|
US Dollar Notional Amount
|
|
Traded Exchange Rate
|
|
Settlement Date
|
|
|
(In Thousands)
|
|
|
|
|
Forward purchase euro
|
|
$
|
509
|
|
|
1.07
|
|
1/18/2017
|
Forward purchase pounds sterling
|
|
$
|
6,258
|
|
|
1.28
|
|
1/18/2017
|
Forward purchase Mexican peso
|
|
$
|
6,740
|
|
|
20.18
|
|
1/18/2017
|
Forward sale Norwegian krone
|
|
$
|
2,322
|
|
|
8.53
|
|
1/18/2017
|
Forward sale Mexican peso
|
|
$
|
2,483
|
|
|
20.18
|
|
1/18/2017
|
Under this program, we and CCLP may enter into similar derivative contracts from time to time. Although contracts pursuant to this program will serve as an economic hedge of the cash flow of our currency exchange risk exposure, they are not formally designated as hedge contracts or qualify for hedge accounting treatment. Accordingly, any change in the fair value of these derivative instruments during a period will be included in the determination of earnings for that period.
The fair value of foreign currency derivative instruments are based on quoted market values as reported to us by our counterparty (a level 2 fair value measurement). The fair values of our foreign currency derivative instruments as of
December 31, 2017
and
2016
, are as follows:
|
|
|
|
|
|
|
|
|
|
|
Foreign currency derivative instruments
|
Balance Sheet Location
|
|
Fair Value at
December 31, 2017
|
Fair Value at
December 31, 2016
|
|
|
|
|
(In Thousands)
|
Forward purchase contracts
|
|
Current assets
|
|
$
|
111
|
|
$
|
—
|
|
Forward sale contracts
|
|
Current assets
|
|
130
|
|
81
|
|
Forward purchase contracts
|
|
Current liabilities
|
|
(113
|
)
|
(371
|
)
|
Total
|
|
|
|
$
|
(127
|
)
|
$
|
(290
|
)
|
None of the foreign currency derivative contracts contain credit risk related contingent features that would require us to post assets or collateral for contracts that are classified as liabilities. During the year ended
December 31, 2017
,
2016
, and
2015
, we recognized approximately $
(1.3) million
,
$2.0 million
and
$0.6 million
of net (gains) losses reflected in other expense, net, associated with our foreign currency derivative program.
NOTE P
— INCOME (LOSS) PER SHARE
The following is a reconciliation of the common shares outstanding with the number of shares used in the computation of income (loss) per common and common equivalent share for each of the following periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
|
|
(In Thousands)
|
Number of weighted average common shares outstanding
|
|
114,499
|
|
|
87,286
|
|
|
79,169
|
|
Assumed exercise of stock awards
|
|
—
|
|
|
—
|
|
|
—
|
|
Average diluted shares outstanding
|
|
114,499
|
|
|
87,286
|
|
|
79,169
|
|
For the years
ended December 31, 2015, 2016 and 2017, the average diluted shares outstanding excludes the impact of all outstanding stock awards and stock warrants, as the inclusion of these shares would have been antidilutive due to net loss recorded during the year. In addition, for the years ended December 31, 2016 and 2017, the calculation of diluted earnings per common share excludes the impact of the CCLP Preferred Units, as the inclusion of the impact from conversion of the CCLP Preferred Units into CCLP common units would have been antidilutive.
NOTE Q
— INDUSTRY SEGMENTS
AND GEOGRAPHIC INFORMATION
We manage our operations through
five
reporting segments organized into
four
divisions:
Fluids, Production Testing, Compression, and Offshore
.
Our
Fluids Division
manufactures and markets clear brine fluids, additives, and associated products and services to the oil and gas industry for use in well drilling, completion and workover operations in the United States and in certain countries in Latin America, Europe, Asia, the Middle East and Africa. The division also markets liquid and dry calcium chloride products manufactured at its production facilities or purchased from third-party suppliers to a variety of markets outside the energy industry. The Fluids Division also provides domestic onshore oil and gas operators with a wide variety of water management services.
Our
Production Testing Division
provides frac flowback, production well testing, offshore rig cooling, and other associated services and early production facilities (EPFs) in many of the major oil and gas producing regions in the United States, Mexico, and Canada, as well as in oil and gas basins in certain regions in South America, Africa, Europe, the Middle East and Australia.
Our
Compression Division
is a provider of compression services and equipment for natural gas and oil production, gathering, transportation, processing, and storage. The Compression Division's equipment sales business includes the fabrication and sale of standard compressor packages, custom-designed compressor packages and oilfield pump systems designed and fabricated at the division's facilities. The Compression Division's aftermarket business provides compressor package reconfiguration and maintenance services and compressor package parts and components manufactured by third-party suppliers. The Compression Division provides its services and equipment to a broad base of natural gas and oil exploration and production, midstream, transmission, and storage companies operating throughout many of the onshore producing regions of the United States, as well as in a number of foreign countries, including Mexico, Canada and Argentina.
Our
Offshore Division
consists of
two
operating segments, both of which were disposed on March 1, 2018: Offshore Services and Maritech. The Offshore Services segment provided services primarily to the offshore oil and gas industry, consisting of: (1) downhole and subsea services, such as well plugging and abandonment and inspection, repair and maintenance services; (2) decommissioning and certain construction services utilizing heavy lift barges and various cutting technologies with regard to offshore oil and gas production platforms and pipelines; and (3) conventional and saturation diving services.
The
Maritech
segment was a limited oil and gas production operation. During 2011 and the first quarter of 2012, Maritech sold substantially all of its oil- and gas-producing property interests. Maritech’s operations consisted primarily of the ongoing abandonment and decommissioning associated with its remaining offshore wells and production platforms.
We generally evaluate the performance of and allocate resources to our segments based on profit or loss from their operations before income taxes and nonrecurring charges, return on investment, and other criteria. Transfers between segments and geographic areas are priced at the estimated fair value of the products or services as negotiated between the operating units. “Corporate overhead” includes corporate general and administrative expenses, corporate depreciation and amortization, interest income and expense, and other income and expense.
Summarized financial information concerning the business segments is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
|
|
(In Thousands)
|
Revenues from external customers
|
|
|
|
|
|
|
|
|
|
Product sales
|
|
|
|
|
|
|
|
|
|
Fluids Division
|
|
$
|
226,606
|
|
|
$
|
176,882
|
|
|
$
|
306,307
|
|
Production Testing Division
|
|
12,108
|
|
|
—
|
|
|
6,944
|
|
Compression Division
|
|
66,691
|
|
|
71,809
|
|
|
141,461
|
|
Offshore Division
|
|
|
|
|
|
|
|
|
|
Offshore Services
|
|
760
|
|
|
116
|
|
|
611
|
|
Maritech
|
|
538
|
|
|
751
|
|
|
2,438
|
|
Total Offshore Division
|
|
1,298
|
|
|
867
|
|
|
3,049
|
|
Consolidated
|
|
$
|
306,703
|
|
|
$
|
249,558
|
|
|
$
|
457,761
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Services and rentals
|
|
|
|
|
|
|
|
|
|
Fluids Division
|
|
$
|
108,694
|
|
|
$
|
69,625
|
|
|
$
|
117,459
|
|
Production Testing Division
|
|
80,104
|
|
|
59,509
|
|
|
122,292
|
|
Compression Division
|
|
228,896
|
|
|
239,566
|
|
|
316,178
|
|
Offshore Division
|
|
|
|
|
|
|
|
|
|
Offshore Services
|
|
95,981
|
|
|
76,506
|
|
|
116,455
|
|
Maritech
|
|
—
|
|
|
—
|
|
|
—
|
|
Intersegment eliminations
|
|
—
|
|
|
—
|
|
|
—
|
|
Total Offshore Division
|
|
95,981
|
|
|
76,506
|
|
|
116,455
|
|
Corporate overhead
|
|
—
|
|
|
—
|
|
|
—
|
|
Consolidated
|
|
$
|
513,675
|
|
|
$
|
445,206
|
|
|
$
|
672,384
|
|
|
|
|
|
|
|
|
Interdivision revenues
|
|
|
|
|
|
|
|
|
Fluids Division
|
|
$
|
31
|
|
|
$
|
87
|
|
|
$
|
278
|
|
Production Testing Division
|
|
1,930
|
|
|
4,109
|
|
|
4,668
|
|
Compression Division
|
|
—
|
|
|
—
|
|
|
—
|
|
Offshore Division
|
|
|
|
|
|
|
|
|
|
Offshore Services
|
|
—
|
|
|
903
|
|
|
5,128
|
|
Maritech
|
|
—
|
|
|
—
|
|
|
—
|
|
Intersegment eliminations
|
|
—
|
|
|
(903
|
)
|
|
(5,128
|
)
|
Total Offshore Division
|
|
—
|
|
|
—
|
|
|
—
|
|
Interdivision eliminations
|
|
(1,961
|
)
|
|
(4,196
|
)
|
|
(4,946
|
)
|
Consolidated
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
|
|
|
|
|
|
|
Fluids Division
|
|
$
|
335,331
|
|
|
$
|
246,595
|
|
|
$
|
424,044
|
|
Production Testing Division
|
|
94,142
|
|
|
63,618
|
|
|
133,904
|
|
Compression Division
|
|
295,587
|
|
|
311,374
|
|
|
457,639
|
|
Offshore Division
|
|
|
|
|
|
|
|
|
|
Offshore Services
|
|
96,741
|
|
|
77,525
|
|
|
122,194
|
|
Maritech
|
|
538
|
|
|
751
|
|
|
2,438
|
|
Intersegment eliminations
|
|
—
|
|
|
(903
|
)
|
|
(5,128
|
)
|
Total Offshore Division
|
|
97,279
|
|
|
77,373
|
|
|
119,504
|
|
Corporate overhead
|
|
—
|
|
|
—
|
|
|
—
|
|
Interdivision eliminations
|
|
(1,961
|
)
|
|
(4,196
|
)
|
|
(4,946
|
)
|
Consolidated
|
|
$
|
820,378
|
|
|
$
|
694,764
|
|
|
$
|
1,130,145
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
|
|
(In Thousands)
|
Depreciation, amortization, and accretion
|
|
|
|
|
|
|
|
|
|
Fluids Division
|
|
$
|
23,797
|
|
|
$
|
28,338
|
|
|
$
|
35,125
|
|
Production Testing Division
|
|
10,593
|
|
|
16,221
|
|
|
24,080
|
|
Compression Division
|
|
69,142
|
|
|
72,159
|
|
|
82,024
|
|
Offshore Division
|
|
|
|
|
|
|
Offshore Services
|
|
10,678
|
|
|
11,086
|
|
|
11,500
|
|
Maritech
|
|
1,428
|
|
|
1,362
|
|
|
1,375
|
|
Intersegment eliminations
|
|
—
|
|
|
—
|
|
|
—
|
|
Total Offshore Division
|
|
12,106
|
|
|
12,448
|
|
|
12,875
|
|
Corporate overhead
|
|
521
|
|
|
429
|
|
|
911
|
|
Consolidated
|
|
$
|
116,159
|
|
|
$
|
129,595
|
|
|
$
|
155,015
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
|
|
|
|
|
|
|
Fluids Division
|
|
$
|
124
|
|
|
$
|
32
|
|
|
$
|
22
|
|
Production Testing Division
|
|
6
|
|
|
42
|
|
|
—
|
|
Compression Division
|
|
42,309
|
|
|
38,271
|
|
|
35,235
|
|
Offshore Division
|
|
|
|
|
|
|
|
|
|
Offshore Services
|
|
—
|
|
|
—
|
|
|
—
|
|
Maritech
|
|
—
|
|
|
12
|
|
|
29
|
|
Intersegment eliminations
|
|
—
|
|
|
—
|
|
|
—
|
|
Total Offshore Division
|
|
—
|
|
|
12
|
|
|
29
|
|
Corporate overhead
|
|
15,588
|
|
|
21,639
|
|
|
19,879
|
|
Consolidated
|
|
$
|
58,027
|
|
|
$
|
59,996
|
|
|
$
|
55,165
|
|
|
|
|
|
|
|
|
Income (loss) before taxes
|
|
|
|
|
|
|
|
|
|
Fluids Division
|
|
$
|
68,540
|
|
|
$
|
10,430
|
|
|
$
|
80,789
|
|
Production Testing Division
|
|
(17,465
|
)
|
|
(35,471
|
)
|
|
(55,720
|
)
|
Compression Division
|
|
(37,246
|
)
|
|
(136,327
|
)
|
|
(146,798
|
)
|
Offshore Division
|
|
|
|
|
|
|
Offshore Services
|
|
(14,767
|
)
|
|
(12,025
|
)
|
|
(195
|
)
|
Maritech
|
|
(2,172
|
)
|
|
(1,841
|
)
|
|
(3,833
|
)
|
Intersegment eliminations
|
|
—
|
|
|
—
|
|
|
—
|
|
Total Offshore Division
|
|
(16,939
|
)
|
|
(13,866
|
)
|
|
(4,028
|
)
|
Interdivision eliminations
|
|
(152
|
)
|
|
8
|
|
|
(1
|
)
|
Corporate overhead
(1)
|
|
(57,721
|
)
|
|
(61,864
|
)
|
|
(76,005
|
)
|
Consolidated
|
|
$
|
(60,983
|
)
|
|
$
|
(237,090
|
)
|
|
$
|
(201,763
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
|
|
(In Thousands)
|
Total assets
|
|
|
|
|
|
|
|
|
|
Fluids Division
|
|
$
|
346,974
|
|
|
$
|
322,858
|
|
|
$
|
370,892
|
|
Production Testing Division
|
|
86,304
|
|
|
87,462
|
|
|
134,725
|
|
Compression Division
|
|
784,745
|
|
|
816,148
|
|
|
1,004,760
|
|
Offshore Division
|
|
|
|
|
|
|
|
|
Offshore Services
|
|
119,547
|
|
|
102,715
|
|
|
131,916
|
|
Maritech
|
|
1,587
|
|
|
3,660
|
|
|
18,453
|
|
Intersegment eliminations
|
|
—
|
|
|
—
|
|
|
—
|
|
Total Offshore Division
|
|
121,134
|
|
|
106,375
|
|
|
150,369
|
|
Corporate overhead and eliminations
|
|
(30,543
|
)
|
|
(17,303
|
)
|
|
(24,544
|
)
|
Consolidated
|
|
$
|
1,308,614
|
|
|
$
|
1,315,540
|
|
|
$
|
1,636,202
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
|
|
|
|
|
|
|
Fluids Division
|
|
$
|
20,475
|
|
|
$
|
2,311
|
|
|
$
|
11,104
|
|
Production Testing Division
(2)
|
|
(1,190
|
)
|
|
802
|
|
|
7,843
|
|
Compression Division
(2)
|
|
25,920
|
|
|
11,568
|
|
|
95,586
|
|
Offshore Division
|
|
|
|
|
|
|
|
|
Offshore Services
|
|
5,786
|
|
|
5,913
|
|
|
5,949
|
|
Maritech
|
|
—
|
|
|
—
|
|
|
38
|
|
Intersegment eliminations
|
|
—
|
|
|
—
|
|
|
—
|
|
Total Offshore Division
|
|
5,786
|
|
|
5,913
|
|
|
5,987
|
|
Corporate overhead
|
|
932
|
|
|
472
|
|
|
77
|
|
Consolidated
|
|
$
|
51,923
|
|
|
$
|
21,066
|
|
|
$
|
120,597
|
|
|
|
(1)
|
Amounts reflected include the following general corporate expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017
|
|
2016
|
|
2015
|
|
|
(In Thousands)
|
General and administrative expense
|
|
$
|
46,156
|
|
|
$
|
34,767
|
|
|
$
|
52,189
|
|
Depreciation and amortization
|
|
84
|
|
|
430
|
|
|
913
|
|
Interest expense, net
|
|
15,513
|
|
|
21,157
|
|
|
18,654
|
|
Other general corporate (income) expense, net
|
|
(4,032
|
)
|
|
5,510
|
|
|
4,249
|
|
Total
|
|
$
|
57,721
|
|
|
$
|
61,864
|
|
|
$
|
76,005
|
|
|
|
(2)
|
Amounts presented net of cost of equipment sold during 2017, including
$4.2 million
for our Production Testing Division and
$8.5 million
for our Compression Division.
|
Summarized financial information concerning the geographic areas of our customers and in which we operate at
December 31, 2017
,
2016
, and
2015
,
is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
|
|
(In Thousands)
|
Revenues from external customers:
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
$
|
643,216
|
|
|
$
|
535,613
|
|
|
$
|
896,131
|
|
Canada and Mexico
|
|
35,975
|
|
|
34,560
|
|
|
44,542
|
|
South America
|
|
28,167
|
|
|
20,480
|
|
|
26,554
|
|
Europe
|
|
80,721
|
|
|
71,882
|
|
|
80,432
|
|
Africa
|
|
700
|
|
|
10,345
|
|
|
20,761
|
|
Asia and other
|
|
31,599
|
|
|
21,884
|
|
|
61,725
|
|
Total
|
|
$
|
820,378
|
|
|
$
|
694,764
|
|
|
$
|
1,130,145
|
|
Transfers between geographic areas:
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Canada and Mexico
|
|
—
|
|
|
—
|
|
|
—
|
|
South America
|
|
—
|
|
|
—
|
|
|
—
|
|
Europe
|
|
2,025
|
|
|
93
|
|
|
1,252
|
|
Africa
|
|
—
|
|
|
—
|
|
|
—
|
|
Asia and other
|
|
—
|
|
|
—
|
|
|
—
|
|
Eliminations
|
|
(2,025
|
)
|
|
(93
|
)
|
|
(1,252
|
)
|
Total revenues
|
|
$
|
820,378
|
|
|
$
|
694,764
|
|
|
$
|
1,130,145
|
|
Identifiable assets:
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
$
|
1,131,650
|
|
|
$
|
1,132,986
|
|
|
$
|
1,403,916
|
|
Canada and Mexico
|
|
62,537
|
|
|
64,163
|
|
|
74,260
|
|
South America
|
|
23,352
|
|
|
21,354
|
|
|
25,603
|
|
Europe
|
|
61,000
|
|
|
53,713
|
|
|
64,695
|
|
Africa
|
|
3,696
|
|
|
5,711
|
|
|
7,542
|
|
Asia and other
|
|
26,379
|
|
|
37,613
|
|
|
60,186
|
|
Eliminations
|
|
—
|
|
|
—
|
|
|
—
|
|
Total identifiable assets
|
|
$
|
1,308,614
|
|
|
$
|
1,315,540
|
|
|
$
|
1,636,202
|
|
During each of the three years ended
December 31, 2017
,
2016
, and
2015
, no single customer accounted for more than 10% of our consolidated revenues.
NOTE R
—
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)
As part of the Offshore Division activities, Maritech and its subsidiaries previously
acquired oil and gas reserves and operated the properties in exchange for assuming the proportionate share of the well abandonment and decommissioning obligations associated with such properties. Accordingly, our Maritech segment is included within our Offshore Division. During 2011 and the first quarter of 2012, Maritech sold substantially all of its oil and gas producing property interests. In March 2018, we closed the Maritech Asset Purchase Agreement with Orinoco that provided for the purchase by Orinoco of the Maritech Properties. Also in March 2018, we finalized the Maritech Equity Purchase Agreement with Orinoco, that provided for the purchase by Orinoco of the Maritech Equity Interests. Maritech's operations prior to March 2018 consisted primarily of the ongoing abandonment and decommissioning associated with its remaining offshore wells and production platforms. Accordingly, information regarding costs incurred in property acquisition, exploration, and development activities, capitalized costs related to oil and gas producing activities, estimated quantities of oil and gas reserves, and standardized measure of discounted future net cash flows relating to oil and gas reserves have not been presented, as such information is immaterial during each of the three years in the period ended
December 31, 2017
.
Results of Operations for Oil and Gas Producing Activities
Results of operations for oil and gas producing activities excludes general and administrative
and interest expenses directly related to such activities as well as any allocation of corporate or divisional overhead.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
|
|
(In Thousands)
|
Oil and gas sales revenues
|
|
$
|
538
|
|
|
$
|
751
|
|
|
$
|
2,438
|
|
Production (lifting) costs
|
|
1,234
|
|
|
643
|
|
|
921
|
|
Excess decommissioning and abandonment costs
|
|
—
|
|
|
2,593
|
|
|
2,665
|
|
Accretion expense
|
|
1,382
|
|
|
1,362
|
|
|
1,375
|
|
Pretax income (loss) from producing activities
|
|
(2,078
|
)
|
|
(3,847
|
)
|
|
(2,523
|
)
|
Income tax expense (benefit)
|
|
—
|
|
|
—
|
|
|
—
|
|
Results of oil and gas producing activities
|
|
$
|
(2,078
|
)
|
|
$
|
(3,847
|
)
|
|
$
|
(2,523
|
)
|
NOTE S
— QUARTERLY FINANCIAL INFORMATION (Unaudited)
Summarized quarterly financial data for
2017
and
2016
is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended 2017
|
|
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
|
|
(In Thousands, Except Per Share Amounts)
|
Total revenues
|
|
$
|
168,001
|
|
|
$
|
208,369
|
|
|
$
|
216,364
|
|
|
$
|
227,644
|
|
Gross profit
|
|
14,265
|
|
|
26,888
|
|
|
43,507
|
|
|
15,164
|
|
Net loss
|
|
(11,252
|
)
|
|
(14,619
|
)
|
|
(1,338
|
)
|
|
(34,974
|
)
|
Net income (loss) attributable to TETRA stockholders
|
|
(2,463
|
)
|
|
(10,991
|
)
|
|
3,145
|
|
|
(28,739
|
)
|
Net income (loss) per share attributable to TETRA stockholders
|
|
$
|
(0.02
|
)
|
|
$
|
(0.10
|
)
|
|
$
|
0.03
|
|
|
$
|
(0.25
|
)
|
Net income (loss) per diluted share attributable to TETRA stockholders
|
|
$
|
(0.02
|
)
|
|
$
|
(0.10
|
)
|
|
$
|
0.03
|
|
|
$
|
(0.25
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended 2016
|
|
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
|
|
(In Thousands, Except Per Share Amounts)
|
Total revenues
|
|
$
|
169,329
|
|
|
$
|
175,660
|
|
|
$
|
176,553
|
|
|
$
|
173,222
|
|
Gross profit
|
|
4,611
|
|
|
16,272
|
|
|
28,753
|
|
|
1,781
|
|
Net loss
|
|
(147,731
|
)
|
|
(29,224
|
)
|
|
(24,028
|
)
|
|
(38,410
|
)
|
Net loss attributable to TETRA stockholders
|
|
(88,325
|
)
|
|
(26,574
|
)
|
|
(15,009
|
)
|
|
(31,554
|
)
|
Net loss per share attributable to TETRA stockholders
|
|
$
|
(1.11
|
)
|
|
$
|
(0.32
|
)
|
|
$
|
(0.16
|
)
|
|
$
|
(0.33
|
)
|
Net loss per diluted share attributable to TETRA stockholders
|
|
$
|
(1.11
|
)
|
|
$
|
(0.32
|
)
|
|
$
|
(0.16
|
)
|
|
$
|
(0.33
|
)
|
Gross profit for the three months ended
December 31, 2017
, includes the impact of
$14.9 million
for certain impairments of long-lived assets.
Gross profit for the three months ended December 31, 2016, includes the impact of
$7.5 million
for certain impairments of long-lived assets. Gross profit for the three months ended March 31, 2016, includes the impact of
$10.7 million
for impairments of long-lived assets, and net loss for this period includes the additional impact of
$106.2 million
for impairment of goodwill.
TETRA Technologies, Inc. and Subsidiaries
Schedule I - Condensed Financial Information of Registrant (Parent Only)
Statement of Financial Position
(In Thousands)
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
2017
|
|
2016
|
Assets
|
|
|
|
Current Assets
|
|
|
|
Cash, excluding restricted cash
|
$
|
6,054
|
|
|
$
|
—
|
|
Accounts receivable
|
44,796
|
|
|
35,058
|
|
Inventories
|
43,527
|
|
|
44,765
|
|
Prepaid expenses and other current assets
|
3,145
|
|
|
7,771
|
|
Other current assets
|
—
|
|
|
—
|
|
Total current assets
|
97,522
|
|
|
87,594
|
|
Property, plant and equipment
|
362,624
|
|
|
341,985
|
|
Less accumulated depreciation
|
(206,131
|
)
|
|
(188,268
|
)
|
Property, plant, and equipment, net
|
156,493
|
|
|
153,717
|
|
Other assets, including investment in and amounts due from wholly owned subsidiaries
|
897,488
|
|
|
833,395
|
|
Total assets
|
1,151,503
|
|
|
1,074,706
|
|
|
|
|
|
Liabilities and stockholders' equity
|
|
|
|
Current liabilities
|
54,190
|
|
|
32,999
|
|
Long-term debt
|
117,679
|
|
|
119,640
|
|
Other non-current liabilities
|
771,554
|
|
|
688,542
|
|
Total liabilities
|
943,423
|
|
|
841,181
|
|
|
|
|
|
Stockholders' equity
|
|
|
|
Common stock
|
1,185
|
|
|
1,179
|
|
Other stockholders' equity
|
250,662
|
|
|
283,631
|
|
Accumulated other comprehensive income (loss)
|
(43,767
|
)
|
|
(51,285
|
)
|
Total Stockholders' Equity
|
208,080
|
|
|
233,525
|
|
Total liabilities and equity
|
$
|
1,151,503
|
|
|
$
|
1,074,706
|
|
TETRA Technologies, Inc. and Subsidiaries
Schedule I - Condensed Financial Information of Registrant (Parent Only)
Statements of Operations
(In Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
Net sales and gross revenues
|
|
$
|
247,558
|
|
|
$
|
163,232
|
|
|
$
|
314,567
|
|
|
|
|
|
|
|
|
Cost of revenues
|
|
161,608
|
|
|
119,350
|
|
|
189,362
|
|
Depreciation, amortization, and accretion
|
|
21,269
|
|
|
25,922
|
|
|
50,708
|
|
General and administrative expenses
|
|
57,840
|
|
|
49,687
|
|
|
69,925
|
|
Interest expense
|
|
16,917
|
|
|
22,550
|
|
|
19,901
|
|
Other (income) expense, net
|
|
(17,656
|
)
|
|
4,247
|
|
|
1,097
|
|
Equity in net loss of subsidiaries
|
|
70,374
|
|
|
181,780
|
|
|
192,242
|
|
|
|
310,352
|
|
|
403,536
|
|
|
523,235
|
|
Income (loss) before taxes and discontinued operations
|
|
(62,794
|
)
|
|
(240,304
|
)
|
|
(208,668
|
)
|
Provision (benefit) for income taxes
|
|
(611
|
)
|
|
(911
|
)
|
|
799
|
|
Income (loss)
|
|
$
|
(62,183
|
)
|
|
$
|
(239,393
|
)
|
|
$
|
(209,467
|
)
|
TETRA Technologies, Inc. and Subsidiaries
Schedule I - Condensed Financial Information of Registrant (Parent Only)
Statements of Cash Flows
(In Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2017
|
|
2016
|
|
2015
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
40,283
|
|
|
$
|
14,861
|
|
|
$
|
100,932
|
|
|
|
|
|
|
|
|
Investing activities:
|
|
|
|
|
|
|
Acquisition of businesses, net of cash acquired
|
|
—
|
|
|
—
|
|
|
—
|
|
Purchases of property, plant and equipment
|
|
(27,863
|
)
|
|
(2,931
|
)
|
|
678
|
|
Proceeds from sale of property, plant, and equipment
|
|
982
|
|
|
1,325
|
|
|
2,146
|
|
Advances and other investing activities
|
|
799
|
|
|
314
|
|
|
1,626
|
|
Other investing activities
|
|
—
|
|
|
(10,000
|
)
|
|
—
|
|
Net cash provided by (used in) investing activities
|
|
(26,082
|
)
|
|
(11,292
|
)
|
|
4,450
|
|
Financing activities:
|
|
|
|
|
|
|
Proceeds from long-term debt
|
|
303,650
|
|
|
349,550
|
|
|
472,896
|
|
Payments of long-term debt
|
|
(309,200
|
)
|
|
(516,900
|
)
|
|
(575,070
|
)
|
Distributions
|
|
—
|
|
|
—
|
|
|
—
|
|
Financing costs and other financing activities
|
|
(2,597
|
)
|
|
(4,494
|
)
|
|
(3,742
|
)
|
Proceeds from issuance of common stock, net of underwriters' discount
|
|
—
|
|
|
168,275
|
|
|
—
|
|
Proceeds from sale of common stock and exercise of stock options
|
|
—
|
|
|
—
|
|
|
303
|
|
Net cash used in financing activities
|
|
(8,147
|
)
|
|
(3,569
|
)
|
|
(105,613
|
)
|
Increase (decrease) in cash
|
|
6,054
|
|
|
—
|
|
|
(231
|
)
|
Cash and cash equivalents at beginning of period
|
|
—
|
|
|
—
|
|
|
231
|
|
Cash and cash equivalents at end of period
|
|
$
|
6,054
|
|
|
$
|
—
|
|
|
$
|
—
|
|
TETRA Technologies, Inc. and Subsidiaries
Schedule I - Condensed Financial Information of Registrant (Parent Only)
NOTE A - BASIS OF PRESENTATION
In the parent-company-only financial statements, the Company's investment in subsidiaries is stated at cost plus equity in undistributed earnings of subsidiaries since the date of the respective acquisition. The Company's share of net income of its unconsolidated subsidiaries is included in consolidated income using the equity method. The parent-company-only financial statements should be read in conjunction with the Company's consolidated financial statements.
Previously reported financial statement information for financial position, results of operations, and cash flows has been modified to conform to the current period presentation.