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 in The Woodlands, Texas. 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 by writing or telephoning 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, compression services and equipment, and selected offshore services including well plugging and abandonment, decommissioning, and diving. We also have a limited domestic oil and gas production business. We are 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 in many of the major oil and gas producing regions in the United States, Mexico, and Canada, as well as in 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: Offshore Services and Maritech. The Offshore Services segment provides: (1) downhole and subsea services such as well plugging and abandonment, and workover 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 is 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 consist primarily of the ongoing abandonment and decommissioning associated with its remaining offshore wells and production platforms. Maritech intends to acquire a portion of these services from the Offshore Division’s Offshore Services segment.
We continue to pursue a long-term growth strategy that includes expanding our existing core businesses, with the exception of the Maritech segment, 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.
Proactive Strategy to Improve Liquidity and Strengthen Balance Sheet in 2016
During 2016, we were proactive in preparing for changes in the market environment by managing our cost structure, reducing capital expenditures and strengthening our balance sheet. While remaining committed to our long-term growth strategies, our near-term focus during this period of reduced activity and demand was to preserve and enhance liquidity through strategic operating and financial measures.
These efforts included:
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In May 2016, we repurchased an aggregate principal amount of $100.0 million of our Series 2010-A Senior Notes, Series 2010-B Senior Notes, and Series 2013 Senior Notes, representing the total outstanding principal amount of those notes.
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In June 2016, we issued and sold 11.5 million shares of common stock in a public offering.
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In July and December 2016, we entered into amendments of the agreements governing our bank revolving credit facility and our 11% Senior Note to, among other things, favorably amend certain financial covenants.
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In December 2016, we issued and sold 22.3 million shares of common stock and warrants to purchase 11.2 million shares of common stock in a public offering.
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In the June 2016 and December 2016 equity offerings we received aggregate net proceeds of
$168.3 million
, which were primarily used to retire outstanding long-term debt.
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In May 2016 and November 2016, our CSI Compressco LP subsidiary ("CCLP") entered into amendments of the agreement governing its bank revolving credit facility to, among other things, favorably amend certain financial covenants
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In August 2016 and September 2016, CCLP issued and sold its newly authorized Series A Convertible Preferred Units in a private placement and used the aggregate net proceeds of $77.3 million to reduce outstanding long-term debt. We purchased a portion of the CCLP Preferred Units for $10.0 million.
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(For detailed information on each of these items, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation.")
Each of the above described liquidity and balance sheet measures has been implemented to position us to be able to capitalize on growth opportunities as they arise in connection with the long-anticipated recovery of the oil and gas services industry. In 2017, we are seeing indicators of improving demand for certain of our products and services. We and CCLP intend to continue taking the actions we believe appropriate to strengthen our balance sheet and to position us financially to be able to capitalize on opportunities in the recovering market.
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 bottomhole 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: onsite 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, continues to be used for our customer's projects in the U.S. Gulf of Mexico. 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 to support the hydraulic fracturing in unconventional well completions for domestic onshore oil and gas operators. These services include 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 potable water.
The Fluids Division manufactures liquid and dry calcium chloride, 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. Liquid 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 liquid and dry calcium chloride manufacturing facilities are located in the United States and Finland. We also acquire liquid and dry 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. 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 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 fracking 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 Argentina, Brazil, Canada, Kurdistan, Mexico, Saudi Arabia, and certain countries in Europe, Africa, and the Middle East. Production Testing operations in Canada are provided through our Greywolf Energy Services ("Greywolf") subsidiary.
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 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 as well as in a number of foreign countries, including Mexico, Canada, and Argentina.
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 6,000 compressor packages providing in excess of 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, 2016
, is summarized in the following table:
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Range of Horsepower Per Package
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Number of Packages
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Aggregate Horsepower
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% of Total Aggregate Horsepower
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0 - 100
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3,904
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183,100
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16.4
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%
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101 - 800
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1,626
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457,809
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41.1
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%
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Over 800
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353
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473,403
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42.5
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%
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Total
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5,883
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1,114,312
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100
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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 CSI Compressco LP subsidiary ("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, 2016
, common units held by the public represent approximately a 56% 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.
Offshore Services Segment.
The Offshore Services segment provides: (1) downhole and subsea services such as well plugging and abandonment, and workover 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 provide these services to offshore oil and gas operators, primarily in the U.S. Gulf of Mexico. We offer comprehensive, integrated services, including individualized engineering consultation and project management services.
In providing services, our Offshore Services segment utilizes rigless offshore plugging and abandonment equipment packages, two heavy lift barges, several dive support vessels, and other dive support assets that we own. In addition, we lease other assets from third parties and engage third-party contractors whenever necessary. The Offshore Services segment provides a wide variety of conventional and saturation diving services to its customers through its Epic Diving & Marine Services subsidiary ("EPIC"). Well abandonment, decommissioning, diving, and certain construction services are performed primarily in the U.S. Gulf of Mexico. The Offshore Services segment provides offshore cutting services and tool rentals through its EOT Cutting Services ("EOT") subsidiary. The Offshore Services segment also utilizes specialized equipment and engineering expertise to address a variety of specific platform construction and decommissioning issues, including those associated with platforms that have been toppled or severely damaged by hurricanes and other windstorms. The Offshore Services segment provides services to major oil and gas companies and independent operators, including Maritech, through its facilities located in Broussard, Belle Chasse, Fourchon, and Houma, Louisiana.
Our Offshore Services segment’s fleet of service vessels has expanded and contracted in size in recent years in response to changing demands for its services. With the TETRA Hedron, a 1,600-metric-ton heavy lift derrick barge, and the TETRA Arapaho, a 725-metric-ton heavy lift derrick barge [need to insert language regarding dry dock], we perform heavy lift decommissioning and construction projects and integrated operations on oil and gas production platforms. The Offshore Services segment also performs contract diving operations, utilizing its owned dive service vessels, as well as vessels obtained under long- and short-term leases as needed. Diving services include saturation diving for up to 1,000 foot dive depths as well as mixed gas and surface diving for shallower dives.
Among other factors, demand for our Offshore Service segment’s operations in the U.S. Gulf of Mexico is affected by federal regulations governing the abandonment and decommissioning of offshore wells, production platforms, and pipelines. These regulations include Notice To Lessees 2010-G05: “Decommissioning Guidance for Wells and Platforms” (NTL 2010-G05, known as the “Idle Iron Guidance”). The Bureau of Safety and Environmental Enforcement ("BSEE") issues offshore permits, regulates offshore contractors, and oversees the provisions of the Idle Iron Guidance. The Idle Iron Guidance became effective October 15, 2010, and requires that operators perform and report decommissioning and abandonment plans and activities in accordance with BSEE requirements. The Idle Iron Guidance provides specific guidelines for when an operator has to permanently plug and abandon wells and decommission platforms and related facilities after the occurrence of certain events, including the end of useful operations, cessation of commercial production, and expiration of the lease.
Maritech Segment.
The Maritech segment is 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. Maritech’s remaining operations consist primarily of the ongoing abandonment and decommissioning of its remaining offshore wells, facilities, and production platforms. Maritech intends to acquire a significant portion of these services with regard to such assets that it operates from the Offshore Division’s Offshore Services segment.
The sales of substantially all of Maritech’s oil and gas producing properties during 2011 and 2012 have 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 have ceased. Following these sales, Maritech’s remaining oil and gas reserves and production are negligible. Maritech’s operations consist 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, 2016
, Maritech spent approximately
$77.7 million
on such efforts. Approximately
$45.6 million
of Maritech decommissioning liabilities remain as of
December 31, 2016
, and approximately
$1.0 million
of this amount is planned to be performed during 2017, with the timing of a portion of this work being discretionary.
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. We review the adequacy of Maritech’s decommissioning liabilities whenever indicators suggest that the estimated cash flows underlying the liabilities have changed materially. The timing and amounts of these cash flows are subject to changes in the energy industry environment and may result in additional liabilities being recorded. For a further discussion of Maritech’s 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, utilizing underground brine (tail brine) obtained from Chemtura Corporation ("Chemtura") that contains calcium chloride. We also produce calcium 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 Chemtura, under which the Fluids Division purchases its requirements of raw material bromine from Chemtura’s Arkansas bromine facilities. In addition, we have a long-term agreement with Chemtura under which Chemtura 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 that was constructed in 1985. This plant was acquired in 1988 and is not operable. We currently lease approximately 33,000 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 Chemtura 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. Chemtura 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 that there are adequate alternative suppliers and that 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, which is expected to continue. With the increase in oil and gas pricing in the second half of 2016 and early 2017, we are seeing indicators of improving demand in the North America market, however the international and offshore markets downswing continues.
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 fracking 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. In mid-2016, demand for our North American onshore water management services increased as oil and natural gases 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.
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, Baker Hughes, Chesapeake, Chevron, ConocoPhillips, Devon Energy, EOG Resources, ExxonMobil,
Halliburton, LLOG Exploration, Oklahoma Energy Corp., Petrobras, Pioneer Natural Resources, Saudi Aramco, Schlumberger, Shell, Southwestern Energy, Total, Tullow, and W & T Offshore. 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 on-shore 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. The Production Testing Division plans to continue growing its foreign operations in order to serve major oil and gas markets worldwide. Competition in on-shore 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 ConocoPhillips, Eclipse Resources, Encana, EP Energy, 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, CDM Resource Management, 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 provides 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. We believe that the enforcement of government regulations, including the Idle Iron Guidance, may accelerate the pace at which offshore Gulf of Mexico abandonment and decommissioning will be done in the future.
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 customer 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 Chevron, Fieldwood Energy, Shell, Stone 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 Alliance Offshore, Montco Oilfield Contractors, Oceaneering, Offshore Specialty Fabricators, Inc., 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, 2016
.
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, 2016
, the Compression Division's equipment sales backlog was approximately
$21.6 million
, $19.4 million of which is expected to be recognized in the year ended December 31, 2017, 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.
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, 2016
, we had approximately 2,400 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, 2016
, we owned or licensed fifty-one (51) issued U.S. patents and had thirteen (13) patent applications pending in the United States. We also had thirty-nine (39) owned or licensed patents and twenty-nine (29) patent applications pending in various other countries. 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 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.
The EPA has determined that greenhouse gases present an endangerment to public health and the environment, because they contribute to global warming and climate change. As a result, the EPA has begun to regulate certain sources of greenhouse gases, including air emissions associated with oil and gas production, particularly as they relate to the hydraulic fracturing of natural gas wells. In addition, the EPA has issued regulations requiring the reporting of greenhouse gas emissions from certain sources which include onshore and offshore oil and natural gas production facilities and onshore oil and gas processing, transmission, storage, and distribution facilities. Reporting of greenhouse gas emissions from such facilities is required on an annual basis. The EPA’s rules relating to emissions of greenhouse gases from large, stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA or state environmental agencies from implementing the rules. Further, Congress has considered, and almost one-half of the states have adopted, legislation that seeks to control or reduce emissions of greenhouse gases from a wide-range of sources.
Offshore Operations
During the past five years, several Notices to Lessees ("NTLs"), Safety and Environmental Management Systems ("SEMS") regulations, and other safety regulations implementing additional safety and certification requirements applicable to offshore activities in the Gulf of Mexico were issued. These NTLs and SEMS regulations include requirements by operators to:
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submit well blowout prevention measures and contingency plans, including demonstrating access to subsea blowout containment resources;
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abide by new permitting standards requiring detailed, independently certified descriptions of well design, casing, and cementing;
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follow new performance-based standards for offshore drilling and production operations
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enhance the safety of operations by reducing the frequency and severity of accidents; and
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certify that the operator has complied with all regulations.
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The “Idle Iron Guidance” regulations, which were adopted in 2010 and govern the plugging, abandonment, and decommissioning of U.S. Gulf of Mexico offshore wells and production platforms, are overseen by BSEE. This agency's scope of responsibility includes maintaining an investigation and review unit, providing for public forums, conducting comprehensive environmental analyses, and creating implementation teams to analyze various aspects of the regulatory structure and to help implement the reform agenda.
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, we maintain 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 provide services and products to customers in the Gulf of Mexico, generally pursuant to written master services agreements that create insurance and indemnity obligations for both parties. If there was an explosion or similar catastrophic event on an offshore location where we are providing services and products, under the majority of our master services agreements with our customers:
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We would be required to indemnify our customer for any claims for injury, death, or property loss or destruction made against them by us or our subcontractors or our subcontractor’s employees. The customer would be required to indemnify us for any claims for injury, death, or property loss or destruction made against us by the customer or its other subcontractors or the employees of the customer or its other subcontractors. These indemnities are intended to apply regardless of the cause of such claims, including but not limited to, the negligence of the indemnified party. Our insurance is structured to cover the cost of defense and any resulting liability from all indemnified claims, up to policy limits.
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The customer would be required to indemnify us for all claims for injury, death, or property loss or destruction made against us by a third party that arise out of the catastrophic event, regardless of the cause of such claims, including but not limited to, our negligence or our subcontractors’ negligence. Our insurance is structured to cover the cost of defense and any resulting liability from all such claims; however, our insurance would be applicable to the claim only if the customer defaulted or otherwise breached its indemnity obligations to us.
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The customer would be required to indemnify us for all claims made against us for environmental pollution or contamination that arise out of the catastrophic event, regardless of the cause of such claims, including our negligence or the negligence of our subcontractors. Our insurance is structured to cover the cost of defense and any resulting liability from all such claims; however, our insurance would be applicable to the claim only if the customer defaulted or otherwise breached its indemnity obligations to us.
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Following the 2011 and 2012 sales of substantially all of Maritech’s offshore producing properties, we no longer participate in offshore drilling activities. However, Maritech and our Offshore Services segment engage contractors to provide well abandonment and related services and products on Maritech’s remaining offshore oil and gas production platforms and associated wells, generally pursuant to written master services agreements that create insurance and indemnity obligations for both parties. If there was an environmental event on an offshore Maritech location where a Maritech contractor was providing services and products, under a majority of Maritech’s master services agreements with its contractors, Maritech would be required to indemnify its contractor for any claims against the contractor for injury, death, or property loss or destruction brought by Maritech, its other subcontractors, or its or their respective employees. The contractor would be required to indemnify Maritech for any claims for injury, death, or property loss or destruction made against Maritech by the contractor or its subcontractors or the employees of the contractor or its subcontractors. These indemnities would apply regardless of the cause of such claims, including the negligence of the indemnified party. Maritech’s insurance is structured to cover the cost of defense and any resulting liability from all indemnified claims, up to policy limits.
In accordance with applicable regulations, Maritech maintains an oil spill response plan with the BSEE and has designated contractors who are trained as qualified individuals and are prepared to coordinate a response to any spill or leak. Maritech also has contracts in place to assure that a complete and experienced resource team is available as required.
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 increased during the second half of 2016 to a high of $54.01 per barrel in December 2016, market reports indicate prices are not expected to increase materially in 2017. 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 the depressed oil and natural gas prices continue, they could have a material adverse effect on our business, consolidated results of operations, and consolidated financial condition. Should current market conditions worsen or persist 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 the current 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, impairments of long-lived assets, and
plugging,
abandonment, and decommissioning
costs
on Maritech’s remaining offshore production platforms,
wells,
and pipelines.
Several of our customers reduced their capital expenditures in 2016 and have publicly announced further reductions in their capital expenditure plans for 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 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 first quarter of 2016, we recorded additional consolidated long-lived asset impairments (excluding goodwill impairments) of approximately
$10.7 million
. During the two year period ending
December 31, 2016
, we have recorded a total of
$62.3 million
of long-lived asset impairments. A continuation of the depressed commodity prices and/or further 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.
Due to decreases in our stock price and CCLP's common unit price and the expected future cash flows from certain of our reporting units, we recorded approximately
$106.2 million
of goodwill impairments during the fourth quarter of
2016
. During the two year period ending December 31, 2016, we have recorded a total of approximately
$283.2 million
of goodwill impairments. Following these goodwill impairments, as of December 31, 2016, 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 the price of CCLP's common units, or future cash flows and slower growth rates in our industry. If economic and market conditions decline further, 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.
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.
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 Chemtura Corporation 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 Chemtura, if we were unable to acquire
these
raw materials
at reasonable prices for a prolonged period, our business could be materially and adversely affected.
Some of the well plugging, abandonment,
and decommissioning services performed by our Offshore Services segment require the use of vessels, diving, cutting, and other equipment, and services provided by third parties. We lease equipment and obtain services from certain providers,
and there can be no assurance that this equipment and these services will be available at reasonable prices in the future.
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. Reductions in employee compensation that were put into effect during 2016 could lead to increased turnover and loss of key personnel. A lack of qualified personnel, could adversely affect operating results.
Operating, Technological, and Strategic Risks
We may not fully realize the benefits from the CSI Acquisition.
As a result of the significant decline in oil and gas prices since the CSI Acquisition, we do not expect to realize all of the anticipated benefits from the CSI Acquisition. In addition, a portion of the expected benefits may not be realized if we are unable to fully and efficiently integrate the business and operations of CSI. While significant steps to integrate and consolidate operations functions have been accomplished, the integration of certain administrative functions has yet to be completed. We are currently converting and consolidating CSI's financial accounting, operating, and information systems environment into our system environment. There can be no assurances that these system integration efforts will accomplish all the targeted efficiencies, or that they will not be more costly or take longer to accomplish than what we currently estimate.
We performed an inspection of the assets to be acquired, which we believe to be generally consistent with industry practices. However, there could be environmental or other problems that are not necessarily observable even when the inspection is undertaken. If problems are identified after closing of the CSI Acquisition, the stock purchase agreement provides for limited recourse against the seller.
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, including one of our heavy lift barges and certain dive support vessels, 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 vessels or 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 marine barges and vessels, heavy equipment, offshore production platforms,
chemical manufacturing plants,
and the performance of heavy lift and diving services involve particularly high levels of risk. In addition, certain of our employees who perform services on offshore platforms and vessels 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 obtain 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. Due to the sale of substantially all of Maritech's oil and gas properties, typical operational risk coverage for its remaining properties, such as removal of debris, operators extra expense, control of well, and pollution and cleanup coverage, is not available at economical rates. 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.
We could incur losses on fixed price contracts.
Due to competitive market conditions, a portion of our well abandonment and decommissioning projects may be performed on a lump sum basis. Pursuant to these types of contracts, defined work is delivered for a fixed price, and extra work, which is subject to customer approval, is charged separately. The revenue, cost, and gross profit realized on these types of contracts can vary from the estimated amount because of changes in offshore conditions, increases in the scope of the work to be performed, increased site clearance efforts required, labor and equipment availability, cost and productivity levels, and the performance level of other contractors. In addition, unanticipated events, such as accidents, work delays, significant changes in the condition of platforms or wells, downhole problems,
weather,
and environmental or other technical issues, could result in significant losses on these types of projects. These variations and risks may result in our experiencing reduced profitability or losses on these types of projects.
The valuation of decommissioning liabilities is based on estimated data that may be materially incorrect.
Our estimates of future well abandonment and decommissioning liabilities are imprecise and are subject to change due to: (i) changes in the forecasts of the supply, demand, cost and timing of well abandonment and decommissioning services; (ii) additional remediation work required on previously completed well abandonment projects; (iii) damage to wells and infrastructure caused by hurricanes and other natural events; (iv) changes in governmental regulations governing well abandonment and decommissioning work; and (v) other factors. In particular, a portion of the remaining decommissioning liabilities for our Maritech subsidiary relates to an offshore production platform that was toppled and destroyed by a hurricane and the estimate to perform the remaining decommissioning and debris removal work on this property is particularly imprecise due to the unique nature of the work to be performed. During the three year period ended
December 31, 2016
, Maritech increased its combined decommissioning liability by a total of approximately
$77.6 million
, consisting of
$38.4 million
of revisions to its existing liabilities as well as
$39.2 million
from adding new liabilities for remediation work required on projects previously thought to have been completed.
As noted above, Maritech has encountered situations where previously plugged and abandoned wells on its properties have later exhibited a buildup of pressure that 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 by us when we perform 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 or 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. During 2014, Maritech added new decommissioning liabilities of approximately $39.2 million for work performed during the year or related to the estimated cost of future work to be performed on previously plugged and abandoned wells. This additional amount was directly charged to earnings as an operating expense during 2014. Maritech is the last operator of record for its plugged wells and bears the risk of additional future work required as a result of wells becoming under pressure in the future.
New federal requirements for financial assurance on offshore oil and gas decommissioning obligations may restrict our borrowing capacity and impose fines and penalties.
Through our Maritech subsidiary, we have interests in twelve producing oil and gas leases in the U.S. Gulf of Mexico, which may include certain wells, production platforms, pipelines and other facilities located on such leases. As of
December 31, 2016
, Maritech’s carrying value of its decommissioning liabilities associated with these leases, and remaining wells, platforms, and other facilities ("Maritech's Interests") totaled approximately
$45.6 million
. In July 2016, the U.S. Bureau of Ocean Engineering Management ("BOEM") issued a Notice to Lessees and Operators ("NTL 2016-N01") related to such decommissioning liabilities, to clarify the procedures and guidelines that BOEM Regional Directors use to determine if and when additional security may be required to ensure that such liabilities will be satisfied. NTL 2016-N01, which became effective September 12, 2016, provides updated procedures with regard to BOEM's ability to require additional financial security for such liabilities. In connection with NTL 2016-N01, BOEM calculates its own estimate of the decommissioning liabilities associated with all such U.S. Gulf of Mexico leases and other interests, and BOEM has provided to Maritech BOEM's estimate of abandonment liability associated with Maritech's Interests. Maritech is negotiating with BOEM to reduce BOEM's estimate of Maritech's liability to be consistent with Maritech's estimate. The final amount agreed to by BOEM will determine the amount of additional security that Maritech will be required to provide, and could exceed the amount of Maritech's estimate.
Among other things, the NTL 2016-N01 eliminates the “waiver exemption” currently allowed by the BOEM, whereby lessees on the U.S. Gulf of Mexico Outer Continental Shelf meeting certain financial strength and reliability criteria are exempted from posting bonds or other acceptable financial assurances for such lessee’s decommissioning obligations. Also, under NTL 2016-N01, Maritech does not qualify to self-insure. NTL 2016-N01 also implements a phase-in period for establishing compliance with additional security obligations for certain properties, whereby lessees may seek compliance with its additional security requirements under a “tailored plan.” A tailored plan would require securing phased-in compliance in three approximately equal installments during a one-year period from the date of the BOEM approval of the tailored plan, which would require us to fund the satisfaction of such estimated decommissioning liabilities within the required time period. Implementation of NTL 2016-N01 could result in Maritech having to obtain additional bonds and/or having to post collateral to obtain such additional bonds, which could reduce the amount of borrowing capacity we have under our Credit Agreement, thus reducing our liquidity. Alternatively, Maritech could be required to provide other financial assurances, including a
parent company guarantee from us for the benefit of Maritech. We remain hopeful that Maritech's negotiations with the BOEM will result in an acceptable tailored plan that reduces the need for additional financial security. However, if those negotiations do not result in an acceptable tailored plan and if we fail to comply with the current or future orders of BOEM to provide additional surety bonds or other financial assurances, or if Maritech fails to proceed with the remaining decommissioning work to avoid the need for any additional security, BOEM could commence enforcement proceedings or take other remedial action, including assessing civil penalties, ordering suspension of operations or production, or initiating procedures to cancel leases, which, if upheld, could have a material adverse effect on our results of operations and financial condition
.
Weather-Related Risks
Certain of our operations are seasonal and depend, in part, on weather conditions.
The Offshore Division's Offshore Services segment has historically enjoyed its highest vessel utilization rates during the period from April to October, when weather conditions in the Gulf of Mexico are typically more favorable for offshore activities, and has experienced its lowest utilization rates in the period from November to March. Under certain lump sum and other contracts, this segment may bear the risk of delays caused
by adverse weather conditions.
In addition, demand for other products and services we provide are subject to seasonal fluctuations, due in part to weather conditions that cannot be predicted. Accordingly, our operating results may vary from quarter to quarter, depending on weather conditions in applicable areas.
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 significant damage and disruption to our businesses.
A significant portion of our operations is susceptible to adverse weather conditions in the Gulf of Mexico, including hurricanes and other extreme weather conditions. High winds, storm surge, and turbulent seas can cause significant damage and curtail our operations for extended periods during and after such weather conditions, while damage is being assessed and remediated. 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.
A portion of the costs
resulting from
damages
from previous hurricanes has yet to be incurred and may result in significant charges to earnings.
During the past four years, Maritech has performed an extensive amount of well intervention, abandonment, decommissioning, and debris removal associated with its offshore platforms that were destroyed by hurricanes. As of
December 31, 2016
, Maritech has remaining hurricane damage response work associated with one of the downed platforms, and the estimated cost to perform this remaining abandonment, decommissioning, and debris removal work is approximately
$7.9 million
net to our interest. Due to the unique nature of the remaining work to be performed, actual costs could greatly exceed these estimates and, depending on the nature of any excess costs incurred, could result in significant charges to earnings in future periods. All of this
$7.9 million
estimated amount has been accrued as part of Maritech’s decommissioning liabilities. Our estimates of the remaining costs to be incurred may be imprecise.
For a further discussion of the remaining costs resulting from damages from the 2005 and 2008 hurricanes, see Notes to Consolidated Financial Statements, “Note B – Summary of Significant Accounting Policies,
Repair Costs and Insurance Recoveries.
”
We have elected to self-insure windstorm damage to our remaining Maritech assets in the Gulf
of Mexico,
and hurricane damages could result in significant uninsured losses.
Despite the sales of
substantially all of
Maritech’s oil and gas reserves during 2011
and 2012, and expending approximately
$77.7 million
of decommissioning work during the three year period ended
December 31, 2016
, we have remaining
decommissioning liabilities of approximately
$45.6 million
associated with offshore platforms and associated wells to be decommissioned and abandoned.
We have discontinued insurance coverage for windstorm damage and have elected to self-insure these risks. To the extent that remaining offshore platforms and associated wells are not decommissioned and abandoned prior to a windstorm occurring,
Maritech
would be
exposed to losses from windstorm damages and
storms in the future.
Depending on the severity and location of the storms, such losses could be significant and could have a material adverse effect on our financial position, results of operation, and cash flows.
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, 2016
, our total long-term debt outstanding (excluding CCLP) of
$119.6 million
consisted of
$3.2 million
carrying amount under our credit agreement, dated as of June 27, 2006, as subsequently 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") and
$116.4 million
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"). In addition, as of December 31, 2016, our consolidated balance sheet includes
$504.1 million
of long-term debt of CCLP, which consisted of (i)
$217.5 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)
$286.6 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
1.34
to 1 and our leverage ratio was
3.47
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. At
December 31, 2016
, our fixed charge coverage ratio was
1.34
to 1 and our leverage ratio was
3.47
to 1.
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, we have reduced long-term debt from the use of equity offering proceeds and taken 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 believe the steps taken have enhanced our capital structure and operating cash flows and will continue to enhance our operating cash flows in the future. We and CCLP are in compliance with all covenants of our respective long-term debt agreements as of
December 31, 2016
. Based on our financial forecasts as of
March 1, 2017
, 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 1, 2018. 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, 2016, CCLP's balance sheet includes
$504.1 million
of carrying value of long-term debt of CCLP consisting of (i)
$217.5 million
under the CCLP Credit Agreement and (ii)
$286.6 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 November 2016, contains financial ratio covenants requiring CCLP to maintain (i) a minimum interest coverage ratio (which is a ratio of a defined measure of earnings to interest, both measured over the trailing twelve months) of (A) 2.25 to 1 at the end of the fiscal quarters ending during the period from and including December 31, 2016 through June 30, 2018; (B) 2.50 to 1 at the end of the fiscal quarters ending during the period from and including September 30, 2018 and December 31, 2018; and (C) 2.75 to 1 at the end of the fiscal quarters ending during the period from and including March 31, 2019 and thereafter; (ii) a maximum total leverage ratio (which is a ratio of a defined measure of debt to a defined measure of earnings, both measured over the trailing twelve months) of (A) 5.95 to 1 at the end of the fiscal quarters ending during the period from and including December 31, 2016 through June 30, 2018, (B) 5.75 to 1 at the end of the fiscal quarters ending during the period from and including September 30, 2018 and December 31, 2018, and (C) 5.50 to 1 at the end of the fiscal quarters ending during the period from and including March 31, 2019 and thereafter; and (iii) a maximum secured leverage ratio (which is a ratio of a defined measure of secured debt to a defined measure of earnings, both measures over the trailing twelve months) of (A) 3.25 to 1 at the end of the fiscal quarters ending during the period from and including December 31, 2016 through June 30, 2018, and (B) 3.50 to 1 at the end of the fiscal quarters ending during the period from and including September 30, 2018 and thereafter. At
December 31, 2016
, the CCLP consolidated total leverage ratio was
5.40
to 1 (compared to 5.95 to 1 maximum allowed under the CCLP Credit Agreement), its consolidated secured leverage ratio was
2.35
to 1 (compared to a 3.25 to 1 maximum ratio allowed under the CCLP Credit Agreement), and its interest coverage ratio was
3.13
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, 2016
. As a result of the recent decreased demand for certain of CCLP's products and services by CCLP's customers in response to decreased oil and natural gas prices, and CCLP's expectation that the reduced demand will continue for an indefinite period, CCLP has reduced long-term debt from the use of the CCLP Preferred Units offering proceeds and taken strategic cost reduction efforts, including headcount reductions, deferral of salary increases, salary reductions, and other efforts to reduce costs and generate cash. Based on CCLP's financial forecasts as of
February 28, 2017
, 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, 2018. CCLP's plans and forecasts for 2017 include expectations that we will settle certain Omnibus Agreement expenses owed to us by CCLP 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.
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, having an estimated value at the time of sale of approximately $122.0
million pursuant to the purchase and sale agreements. For oil and gas properties Maritech previously operated, the buyer 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 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. 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 current oil and natural gas pricing levels continue or deteriorate further, we expect that one or more of these buyers may be unable to perform the decommissioning work required on properties they acquired from Maritech. To the extent Maritech is required to perform a significant
portion of the abandonment and decommissioning obligations associated with these previously owned oil and gas properties, our financial condition and results of operations may be negatively affected.
During the year ended
December 31, 2016
, continued low oil and natural gas prices have resulted in reduced revenues and cash flows for all oil and gas producing companies, including those companies that bought Maritech properties in the past. Certain of these 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 that are 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 estimates that of the total amount of decommissioning liabilities associated with properties sold to this company, Maritech is exposed to a high level of risk on properties that had decommissioning liabilities at the time they were sold in 2011 of approximately $6 million. Some of these liabilities are currently part of the bankruptcy liquidation plan being administered for this company. This amount, which is net to Maritech's interest, may not be representative of the current fair value of these obligations and does not reflect the potential benefit of bonding that may be available to Maritech if it were to be required to perform such obligations. Maritech and its legal counsel monitor the status of these companies. There can be no assurance that Maritech will not become legally responsible to perform decommissioning work on properties it previously sold, resulting in charges to our future earnings and increases to our future operating cash requirements.
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.
As a former or present owner and operator of its oil and gas property interests, Maritech has certain liabilities for the proper abandonment and decommissioning of these properties. We have guaranteed a portion of the abandonment and decommissioning liabilities of Maritech. With respect to certain properties, Maritech is entitled to be paid by the previous owner of the property in the future for all or a portion of the cost of satisfying these obligations when the liability is satisfied. We and Maritech are subject to the risk that the previous owner(s) will be unable to make these future payments. In addition, for certain remaining Maritech properties that have not been decommissioned or abandoned, the
co-owners
of such properties
are responsible for the payment of their portions of the associated operating expenses and abandonment liabilities. However, if one or more co-owners do not pay their portions, Maritech and any other nondefaulting co-owners may be liable for the defaulted amount. If any required payment is not made by a previous owner or a co-owner and any security is not sufficient to cover the required payment, we could suffer losses, which could be material.
During the year ended
December 31, 2016
, continued decreased oil and natural gas prices have resulted in reduced revenues and cash flows for oil and gas producing companies, including companies that are joint-owners in Maritech oil and gas properties and decommissioning obligations currently owned or from whom Maritech is entitled to receive payments upon satisfaction of certain decommissioning obligations. Certain of these previous owners of Maritech properties who are obligated to pay Maritech in the future are currently experiencing severe financial difficulties and have filed for bankruptcy protection. During 2016, Maritech charged to earnings $2.8 million of such contractual payment receivables no longer considered realizable. The majority of the remaining amounts owed to Maritech by these companies are not contractually required to be paid to Maritech until the future. Nevertheless, we are monitoring the financial condition of these companies, and if current oil and natural gas pricing levels continue or worsen, certain of these companies may be unable to pay Maritech for contractual amounts owed. Maritech intends to take any action necessary to protect Maritech's interests. Although certain of these decommissioning obligations may not be performed for many years, there can be no assurance that the current oil and gas price environment will not result in additional charges to our future earnings and increases to our future operating cash requirements.
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 will 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. 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 42.4% of the outstanding CCLP common units, 12.5% 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:
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our previously existing ownership interest in the common units of CCLP will decrease;
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the amount of cash available for distribution on each CCLP common unit may decrease;
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the voting power attributable to our previously existing CCLP common units will be diminished; and
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the market price of CCLP common units may decline.
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We and CCLP are exposed to interest rate risks with regard to our respective credit facility indebtedness.
As of
December 31, 2016
, we and CCLP have a total of
$220.7 million
outstanding under our respective revolving credit facilities.
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 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. Our operation and decommissioning of offshore properties are subject to and affected by various government regulations, including numerous federal and state environmental, health and safety laws and regulations. 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.
A large portion of the services performed by our Offshore Division's Offshore Services segment and all of Maritech’s
remaining well abandonment and decommissioning
operations are conducted on offshore federal leases and are governed by increasing U.S. government regulations. Government regulations also establish construction requirements for production facilities located on federal offshore leases and govern the plugging and abandonment of wells and the removal of production facilities from these leases.
Operators must abide by Idle Iron Guidance
regulations that regulate the permanent plugging of nonproducing wells and the dismantling of oil and gas production platforms within a certain period of time after they are no longer being used.
BSEE
oversees the provisions of the Idle Iron Guidance.
Under limited circumstances, the
BSEE
could require Maritech or our Offshore Services segment to suspend or terminate their
operations on a federal lease, and both Maritech and our Offshore Services segment could be subject to fines and penalties.
We have significant 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:
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•
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restrictions on repatriating cash back to the United States;
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•
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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;
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•
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government controls and government actions, such as expropriation of assets and changes in legal and regulatory environments;
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•
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import and export license requirements;
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•
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political, social, or economic instability;
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•
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changes in tariffs and taxes;
and
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•
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our limited knowledge of these markets or our inability to protect our interests.
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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, 2016
, approximately $3.2 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.
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.
These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of
the federal Clean Air Act
("CAA").
Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the CAA. The 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 as well as requiring so-called “green” completions at hydraulically fractured natural gas wells beginning in 2015. 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.
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.
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, distribution facilities, heavy lift barge rigs, and dive support vessels.
The following information describes facilities that we leased
or owned as of
December 31, 2016
. 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 33,000 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 Brazil, Mexico, United Arab Emirates, United Kingdom, Saudi Arabia, Iraq, Argentina, Australia and Canada.
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 the United States, Mexico, Canada, and Argentina. 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, the Offshore Services segment owns the following fleet of vessels that it uses in performing its well abandonment, decommissioning, construction, and contract diving operations:
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TETRA Hedron
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Derrick barge with 1,600-metric-ton revolving crane
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TETRA Arapaho
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Derrick barge with 725-metric-ton revolving crane
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Epic Explorer
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210-foot dive support vessel with saturation diving system
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We have access to additional leased vessels as needed to adjust to demand for our services.
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 future remediation costs and 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, 2016
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, compression services and equipment, and selected offshore services including well plugging and abandonment, decommissioning, and diving. We also have 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 in many of the major oil and gas producing regions in the United States, Mexico, and Canada, as well as in basins in certain regions in South America, Africa, Europe, the Middle East, and Australia.
Our
Compression Division
, through our CSI Compressco LP subsidiary ("CCLP"), 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: Offshore Services and Maritech. The Offshore Services segment provides: (1) downhole and subsea services such as well plugging and abandonment and workover 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 is 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 consist primarily of the ongoing abandonment and decommissioning associated with its remaining offshore wells and production platforms. Maritech intends to acquire a portion of these services from the Offshore Division’s Offshore Services segment.
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, 2016
, our consolidated balance sheet includes
$143.2 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 1, 2017
.
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 1, 2017
.
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. These reclassifications include the final allocation of the purchase price of CSI. See Note C - Acquisition for further discussion. In addition, these reclassifications include the presentation of deferred financing costs in accordance with the adoption of ASU No. 2015-03 and ASU No. 2015-15 as further discussed below and the reclassification of the amortization of deferred financing costs from other expense, net to interest expense, net. Additionally, see Note G - Long-Term Debt and Other Borrowings for further discussion and presentation.
During the fourth quarter of 2015, we recorded a correcting adjustment to equity-based compensation expense of approximately
$6.7 million
. The impact of this adjustment was not significant to 2015, or to any prior financial reporting period.
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
, consists primarily of escrowed cash associated with our July 2011 purchase of a heavy lift derrick barge. The escrowed cash is expected to be released to the sellers in 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 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 have entered into a fixed interest rate note, which is scheduled to mature in 2022 and which mitigates this risk on our 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, 2016
, are as follows:
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|
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Year Ended December 31,
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|
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2016
|
|
2015
|
|
2014
|
|
|
(In Thousands)
|
At beginning of period
|
|
$
|
7,847
|
|
|
$
|
2,485
|
|
|
$
|
1,349
|
|
Activity in the period:
|
|
|
|
|
|
|
|
|
|
Provision for doubtful accounts
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|
2,436
|
|
|
5,387
|
|
|
856
|
|
Account (chargeoffs) recoveries
|
|
(3,992
|
)
|
|
(25
|
)
|
|
280
|
|
At end of period
|
|
$
|
6,291
|
|
|
$
|
7,847
|
|
|
$
|
2,485
|
|
Inventories
Inventories are stated at the lower of cost or market value. Cost is determined using the weighted average method. Components of inventories are as follows:
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December 31,
|
|
|
2016
|
|
2015
|
|
|
(In Thousands)
|
Finished goods
|
|
$
|
62,064
|
|
|
$
|
54,587
|
|
Raw materials
|
|
2,429
|
|
|
1,731
|
|
Parts and supplies
|
|
35,548
|
|
|
37,379
|
|
Work in progress
|
|
6,505
|
|
|
23,312
|
|
Total inventories
|
|
$
|
106,546
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|
|
$
|
117,009
|
|
Finished goods inventories include newly manufactured clear brine fluids as well as recycled brines that are repurchased from certain customers. Recycled brines are recorded at cost, using the weighted average method. Work in progress inventories consist 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. During the year ended
December 31, 2016
,
$17.6 million
of CCLP work in progress inventory was transferred to Property, Plant and Equipment. We write down the value of inventory by an amount equal to the difference between the cost of the inventory and its estimated realizable value.
Assets Held for Sale
Assets are classified as held for sale when, among other factors, they are identified and marketed for sale in their present condition, management is committed to their disposal, and the sale of the asset is probable within one year. Assets Held for Sale as of
December 31, 2016
and
December 31, 2015
, consists of certain equipment assets that were expected to be sold during 2016 or early 2017.
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:
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Buildings
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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, 2016
,
2015
, and
2014
was
$120.3 million
,
$138.2 million
, and
$109.2 million
, respectively.
Construction in progress as of December 31, 2016 consists primarily of capitalized system software development costs incurred during 2016. Interest capitalized for the years ended
December 31, 2016
,
2015
, and
2014
was
$0.5 million
,
$0.4 million
, and
$0.8 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
$7.0 million
,
$14.8 million
, and
$9.3 million
for the years ended
December 31, 2016
,
2015
, and
2014
, respectively, and is included in
depreciation, amortization and accretion. The estimated future annual amortization expense of patents, trademarks, and other intangible assets is
$5.6 million
for
2017
,
$5.5 million
for
2018
,
$5.5 million
for
2019
,
$5.5 million
for
2020
, and
$5.2 million
for
2021
.
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 2016, 2015, and 2014, 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. During
2015
, and continuing into
2016
, global oil and natural gas commodity prices, particularly crude oil, decreased significantly. These decreases in commodity prices have had, and are expected to continue to have, a negative impact on industry drilling and capital expenditure activity, which affects the demand for a portion of our products and services.
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 business. If the estimated fair value of the reporting unit is higher than the recorded net book value, no impairment is deemed to exist and no further testing is required. If, however, the estimated fair value of the reporting unit is below the recorded net book value, then a second step must be performed to determine the goodwill impairment required, if any. In this second step, the estimated fair value from the first step is used as the purchase price in a hypothetical acquisition of the reporting unit. Business combination accounting rules are followed to determine a hypothetical purchase price allocation to the reporting unit’s assets and liabilities. The residual amount of goodwill that results from this hypothetical purchase price allocation is compared to the recorded amount of goodwill for the reporting unit, and the recorded amount is written down to the hypothetical amount, if lower. The application of this second step under goodwill impairment testing may also result in impairments of other long-lived assets, including identified intangible assets.
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 the fourth quarter of 2014 and 2015, 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, 2014 and 2015. As a result of the annual goodwill impairment test process described above, we recorded impairments of goodwill of
$64.3 million
during
2014
and
$177.0 million
during
2015
. In addition, 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 certain of our reporting units were less than their respective carrying values as of March 31, 2016. As a result of the goodwill impairment process, we recorded an impairment of goodwill of
$106.2 million
during the three months ended March 31, 2016. See below for further discussion of the goodwill impairments recorded for each of these periods. Following these goodwill impairments, as of
December 31, 2016
, our consolidated goodwill consists of the
$6.6 million
of goodwill attributed to our Fluids reporting unit.
As part of our internal annual business outlook for each of our reporting units that we performed during the fourth quarter of 2016, we considered the global economic environment that has continued to affect demand for our
products and services and has 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 value of our Fluids reporting unit was less than its carrying value as of
December 31, 2016
. As part of the first step of goodwill impairment testing as of December 31, 2016, we updated our annual assessment of the future cash flows for each of our reporting units, applying expected long-term growth rates, discount rates, and terminal values that we consider reasonable for each reporting unit. We have calculated a present value of the respective cash flows for each of the reporting units to arrive at an estimate of fair value under the income approach, and then used the market approach to corroborate these values. Based on these assumptions, as of December 31, 2016, we determined that the fair value of our Fluids Division was significantly in excess of its carrying value, which includes approximately
$6.6 million
of goodwill.
Goodwill Impairment as of March 31, 2016.
During the first three months of 2016, continued low oil and natural gas commodity prices resulted in decreased demand for many of the products and services of each of our reporting units. However, based on assumptions as of March 31, 2016, we determined that the fair value of our Fluids Division was significantly in excess of its carrying value, which includes approximately
$6.6 million
of goodwill. Our Offshore Services and Maritech Divisions had no remaining goodwill as of March 31, 2016. With regard to our Compression Division, demand for low-horsepower wellhead compression services and for sales of compressor equipment decreased significantly and is expected to continue to be decreased for the foreseeable future. In addition, the price per common unit of CCLP as of March 31, 2016 decreased compared to December 31, 2015. Accordingly, the fair value, including the market capitalization for CCLP, for the Compression reporting unit was less than its carrying value as of March 31, 2016, despite impairments recorded as of December 31, 2015. For our Production Testing Division, demand for production testing services decreased in each of the market areas in which we operate, resulting in decreased estimated future cash flows. As a result, the fair value of the Production Testing reporting unit was also less than its carrying value as of March 31, 2016, despite impairments recorded as of December 31, 2015. After making the hypothetical purchase price adjustments as part of the second step of the goodwill impairment test, there was
$0.0 million
residual purchase price to be allocated to the goodwill of both the Compression and Production Testing reporting units. Based on this analysis, we concluded that full impairments of the
$92.4 million
of recorded goodwill for Compression and
$13.9 million
of recorded goodwill for Production Testing were required. Accordingly, during the three month period ended March 31, 2016,
$106.2 million
was charged to Goodwill Impairment expense in the accompanying consolidated statement of operations.
Goodwill Impairment as of
December 31, 2015
.
Throughout 2015 and particularly during the last half of the year, lower oil and natural gas commodity prices resulted in a decreased demand for many of the products and services of each of our reporting units. However, based on assumptions as of December 31, 2015, we determined that the fair value of our Fluids Division was significantly in excess of its carrying value, which includes approximately
$6.6 million
of goodwill. Our Offshore Services and Maritech Divisions had no remaining goodwill as of December 31, 2015. Specifically to our Compression Division, demand for low-horsepower wellhead compression services and for sales of compressor equipment decreased significantly and was expected to continue to be decreased for the foreseeable future. Accordingly, the fair value, including the market capitalization for CCLP, for the Compression reporting unit was less than its respective carrying value as of December 31, 2015. For our Production Testing Division, demand for production testing services decreased in each of the market areas in which we operate, resulting in decreased estimated future cash flows. As a result, the fair value of the Production Testing reporting unit was also less than its respective carrying value as of December 31, 2015. After making the hypothetical purchase price adjustments as part of the second step of the goodwill impairment test, there was
$92.4 million
residual purchase price to be allocated to the goodwill of the Compression reporting unit and approximately
$13.9 million
residual purchase price to be allocated to the goodwill of the Production Testing reporting unit. Based on this analysis, we concluded that an impairment of
$139.4 million
of the
$233.5 million
of recorded goodwill for Compression and an impairment of
$37.6 million
of the
$51.5 million
of recorded goodwill for Production Testing was required.
Goodwill Impairments as of December 31, 2014
. Based on the above assumptions as of December 31, 2014, we determined that the fair value of our Fluids Division was significantly in excess of its carrying value, which includes approximately
$6.6 million
of goodwill. The fair value of our Compression Division exceeded its carrying value by approximately 4%. Throughout 2014, challenging market conditions for our Production Testing and Offshore Services reporting units resulted in both of these reporting units performing below the expectations we had as of December 31, 2013. The late 2014 decrease in commodity prices further weakened these market conditions. Pricing and activity levels in many of the markets that the Production Testing reporting unit serves were affected by increased levels of competition. Our Offshore Services reporting unit experienced decreasing demand for its decommissioning, well abandonment, and contract diving services in the U.S. Gulf of Mexico, the primary market that it serves. Customer delays with regard to significant decommissioning and abandonment projects and the
diminished pricing as a result of increased competition for customer projects combined to negatively affect 2014 profitability for the Offshore Services reporting unit. Accordingly, the fair values for the Production Testing and Offshore Services reporting units were less than their respective carrying values as of December 31, 2014. After making the hypothetical purchase price adjustments as part of the second step of the goodwill impairment test, there was
$53.7 million
residual purchase price to be allocated to the goodwill of Production Testing reporting unit and no residual purchase price to be allocated to the goodwill of Offshore Services. Based on this analysis, we concluded that an impairment of
$60.4 million
of recorded goodwill for Production Testing was required, and an impairment of the entire
$3.9 million
of recorded goodwill for Offshore Services was required.
As of
December 31, 2016
, 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, 2016
, are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fluids
|
|
Production Testing
|
|
Compression
|
|
Offshore Services
|
|
Maritech
|
|
Total
|
|
|
(In Thousands)
|
Balance as of December 31, 2013
|
|
$
|
—
|
|
|
$
|
112,062
|
|
|
$
|
72,161
|
|
|
$
|
3,936
|
|
|
$
|
—
|
|
|
$
|
188,159
|
|
Goodwill adjustments
|
|
—
|
|
|
(64,189
|
)
|
|
—
|
|
|
(3,936
|
)
|
|
—
|
|
|
(68,125
|
)
|
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
|
|
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 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 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.
During the first quarter of 2014, the Offshore Services segment sold the TETRA DB-1 heavy lift barge for a sales price of $
3.0 million
. As a result, an additional impairment of approximately $
9.3 million
was recorded in December 2013 to reduce the carrying value of the TETRA DB-1 to the sales price.
During the fourth quarter of 2014, our Offshore Services segment recorded impairments of approximately
$13.7 million
, primarily associated with a portion of the carrying value of certain of its dive services vessels and equipment and other long lived assets due to expected decreased demand. Our Production Testing segment also recorded impairments of approximately
$14.5 million
, primarily associated with a portion of the carrying value of
certain of its production testing equipment and certain identified intangible assets. Our Fluids Division also recorded impairments of approximately
$5.2 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 estimating the decommissioning liabilities, we perform detailed estimating procedures, analysis, and engineering studies. Whenever practical and cost effective, Maritech will utilize the services of its affiliated companies to perform well abandonment and decommissioning work. When these services are performed by an affiliated company, all recorded intercompany revenues are 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. The timing and amounts of these cash flows are subject to changes in the energy industry environment and may result in additional liabilities to be recorded, which, in turn, would result in direct charges to earnings. Decommissioning work performed for the years
2016
,
2015
, and
2014
was
$4.0 million
,
$10.3 million
, and
$63.3 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,
|
|
2016
|
|
2015
|
|
2014
|
|
(In Thousands)
|
Rental revenue
|
$
|
55,909
|
|
|
$
|
143,601
|
|
|
$
|
92,010
|
|
Rental expenses
|
$
|
25,621
|
|
|
$
|
66,528
|
|
|
$
|
34,501
|
|
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, 2016
,
2015
, and
2014
, was
$9.5 million
,
$13.9 million
, and
$4.7 million
, respectively. Equity-based compensation expense during 2015 includes an immaterial 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 dilutive 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. Effective January 1, 2014, we changed the functional currency in Argentina from the U.S. dollar to the Argentina peso. 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) and totaled
$0.9 million
,
$(1.7) million
, and
$(1.2) million
for the years ended
December 31, 2016
,
2015
and
2014
, 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 other financial instruments, which include cash, restricted cash, accounts receivable, short-term borrowings, and long-term debt pursuant to our bank credit agreements, approximate their carrying amounts. The aggregate fair values of our long-term Senior Notes (as such terms are herein defined) at
December 31, 2016
and
2015
, were approximately
$133.9 million
and
$229.8 million
, respectively, compared to carrying amounts of
$125.0 million
and
$385.0 million
, respectively, as current interest rates on
those dates were different than the stated interest rates on the Senior Notes. The fair values of the publicly tradable CCLP Senior Notes (as herein defined) at
December 31, 2016
and 2015, were approximately
$278.2 million
and
$259.9 million
, respectively, compared to carrying amounts of
$295.9 million
and
$350.0 million
, respectively, (See Note G - Long-Term Debt and Other Borrowings, for further discussion), as current rates on
those dates were different from the stated interest rates on the CCLP Senior Notes. We calculated the fair values of our
Senior Notes as of
December 31, 2016
and
2015
, 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 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 calculate the fair value of the liability for our contingent purchase price consideration obligation in accordance with the WIT Water Transfer, LLC (acquired in January 2014 and doing business as TD Water Transfer) share purchase agreement based upon a probability weighted calculation using the actual and anticipated earnings of the acquired operations (a level 3 fair value measurement). The fair value of the liability for the TD Water Transfer contingent purchase price consideration at December 31, 2015 was
$0
.
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).
A summary of these fair value measurements as of
December 31, 2016
and
2015
, 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
|
|
$
|
95,275
|
|
|
|
|
|
|
|
A summary of these fair value measurements as of
December 31, 2015
, 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, 2015
|
|
(Level 1)
|
|
(Level 2)
|
|
(Level 3)
|
|
|
(In Thousands)
|
Asset for foreign currency derivative contracts
|
|
$
|
23
|
|
|
$
|
—
|
|
|
$
|
23
|
|
|
$
|
—
|
|
Liability for foreign currency derivative contracts
|
|
(385
|
)
|
|
—
|
|
|
(385
|
)
|
|
—
|
|
Acquisition contingent consideration liability
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
|
$
|
(362
|
)
|
|
|
|
|
|
|
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
. During the fourth quarter of 2015, in connection with the review of goodwill impairment for our Compression and Production Testing Divisions, these segments recorded total impairment charges of approximately
$221.1 million
, reflecting the decreased fair value for certain assets. 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, 2016
, 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)
|
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.
A summary of these nonrecurring fair value measurements as of
December 31, 2015
, using the fair value hierarchy, is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using
|
|
|
|
|
Total 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, 2015
|
|
|
|
|
|
|
(In Thousands)
|
Offshore Services assets
|
|
$
|
772
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
772
|
|
|
$
|
6,300
|
|
Offshore Services goodwill
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5,659
|
|
Production Testing equipment
|
|
92,402
|
|
|
—
|
|
|
—
|
|
|
92,402
|
|
|
139,444
|
|
Production Testing intangible assets
|
|
14,476
|
|
|
—
|
|
|
—
|
|
|
14,476
|
|
|
12,310
|
|
Production Testing goodwill
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Fluids equipment and facilities
|
|
13,907
|
|
|
—
|
|
|
—
|
|
|
13,907
|
|
|
37,562
|
|
Other
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
|
$
|
127,880
|
|
|
|
|
|
|
|
|
$
|
221,164
|
|
New Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board ("FASB") issued ASU No. 2014-09, "Revenue from Contracts with Customers." ASU No. 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 No. 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. While a portion of these contract reviews are nearly complete, others are in various stages of completion. While the timing and amount of revenue recognized for a large portion of our customer contractual arrangements under ASU 2014-09 will not change, in other cases the adoption of ASU No. 2014-09 may have an impact, which we are currently evaluating and reviewing. We anticipate adopting ASU 2014-09 on January 1, 2018 using the modified retrospective adoption method.
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 April 2015, the FASB issued ASU No. 2015-05, "Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer's Accounting for Fees Paid in a Cloud Computing Arrangement." The amendments in ASU 2015-05 provide guidance to customers about whether a cloud computing arrangement includes a software license. If a cloud computing arrangement includes a software license, the customer should account for the software license element of the arrangement consistent with other software licenses. If a cloud computing arrangement does not include a software license, the customer should account for the arrangement as a service contract. This guidance became effective for us beginning in the first quarter of 2016, and did not have a material impact on our consolidated financial statements.
In July 2015, the FASB issued ASU No. 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. We do not expect the adoption of this standard to have a 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. Under the new ASU, companies will no longer record excess tax benefits and certain tax deficiencies in additional paid-in capital. Instead, all excess tax benefits and tax deficiencies should be recognized as income tax expense or benefit in the income statement, and additional paid-in capital pools will be eliminated. The ASU requires companies to present excess tax benefits as an operating activity on the statement of cash flows rather than as a financing activity. It will also allow an employer to repurchase more of an employee's shares than it can today for tax withholding purposes without triggering liability accounting and allows companies to make a policy election to account for forfeitures as they occur. The ASU will also require an employer to classify the cash paid to a tax authority when shares are withheld to satisfy its statutory income tax withholding obligation as a financing activity on its statement of cash flows. We plan to account for forfeitures as incurred upon adoption of this ASU. 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. We do not expect the adoption of this standard to have a material impact on our consolidated financial statements.
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 the 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 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.
NOTE C
– ACQUISITIONS
Acquisition of Compressor Systems, Inc.
On
August 4, 2014
, a subsidiary of CCLP acquired all of the outstanding capital stock of CSI for
$825.0 million
cash (the "CSI Acquisition"). Prior to the acquisition, CSI owned one of the largest fleets of natural gas compressor packages in the United States. Headquartered in Midland, Texas, CSI fabricates, sells, and maintains natural gas compressors and provides a full range of compression products and services that covers compression needs throughout the entire natural gas production and transportation cycle to natural gas and oil producing clients. CSI derives revenues through three primary business lines: compression and related services, equipment and parts sales, and aftermarket services. Strategically, the acquisition affords the Compression Division the opportunity to capture significant synergies associated with its product and service offerings and its fabrication operations, to further penetrate new and existing markets, and to achieve administrative efficiencies and other strategic benefits.
For the year ended December 31, 2014, our revenues, depreciation and amortization, and pretax earnings included
$152.5 million
,
$25.2 million
, and
$15.8 million
, respectively, associated with the CSI Acquisition after the closing on August 4, 2014. In addition, CSI
Acquisition-related costs of approximately
$5.5 million
were incurred during the year ended December 31, 2014, consisting of external legal fees, transaction consulting fees, and due diligence costs. These costs have been recognized in general and administrative expenses in the consolidated statements of operations. Approximately
$16.6 million
of deferred financing costs related to the CSI Acquisition were incurred as of the acquisition date and are being amortized over the term of the related debt. An additional
$9.3 million
of interim financing costs related to the CSI Acquisition was incurred and is reflected in Other Expense during the year ended December 31, 2014.
Acquisition of Limited Liability Company Interest
On
January 16, 2014
, we finalized the purchase of the remaining
50%
ownership interest of Ahmad Albinali & TETRA Arabia Company Ltd. (TETRA Arabia, a Saudi Arabian limited liability company) for consideration of
$25.2 million
. The closing of this transaction was pursuant to the terms of the Share Sale and Purchase Agreement entered into as of October 1, 2013, with the existing outside shareholder in TETRA Arabia. TETRA Arabia is a provider of production testing services, offshore rig cooling services, and clear brine fluids products and related services to its primary customer in Saudi Arabia. The acquisition of the remaining
50%
interest of TETRA Arabia results in the Production Testing and Fluids segments owning a
100%
interest in its Saudi Arabian operations, which it will operate directly through the TETRA Arabia entity. Prior to the transaction, our
50%
ownership interest in TETRA Arabia was accounted for under the equity method of accounting, whereby our investment was classified as Other Assets in our consolidated balance sheets, and our share of company earnings was classified as Other Income in the consolidated statements of operations. Following the acquisition, TETRA Arabia is consolidated as a wholly owned subsidiary. The
$25.2 million
purchase price for the
50%
ownership interest includes
$15.0 million
that was paid at closing and an additional
$10.2 million
that was paid on
June 16, 2014
.
Acquisition of TD Water Transfer
On
January 29, 2014
, we acquired the assets and operations of WIT Water Transfer, LLC (doing business as TD Water Transfer) for a cash purchase price of $
15.0 million
paid at closing. In addition, the purchase included contingent consideration of up to $
8.0 million
, depending on a defined measure of earnings over each of the two years subsequent to closing. TD Water Transfer is a provider of water management services to oil and gas operators in the South Texas and North Dakota regions, allowing the Fluids Division to serve customers in additional basins in the U.S.
Pro Forma Financial Information
(Unaudited)
The pro forma information presented below has been prepared to give effect to the acquisition of the remaining
50%
ownership interest of TETRA Arabia and the acquisition of CSI as if each of the transactions had occurred at the beginning of the periods presented. The pro forma information includes the impacts of the allocation of the acquisition purchase price for each acquisition on depreciation and amortization. The pro forma information
also excludes the impact of the remeasurement gain and charge to earnings recorded in connection with the acquisition of the remaining
50%
interest in TETRA Arabia as well as the CSI Acquisition and financing costs charged to earnings during the 2014 periods. The pro forma information is presented for illustrative purposes only and is based on estimates and assumptions we deem appropriate. The impact of the acquisition of TD Water Transfer is not significant and is, therefore, not included in the pro forma information below. The following pro forma information is not necessarily indicative of the historical results that would have been achieved if the acquisition transactions had occurred in the past, and our operating results may have been different from those reflected in the pro forma information below. Therefore, the pro forma information should not be relied upon as an indication of the operating results that we would have achieved if the transactions had occurred at the beginning of the periods presented or the future results that we will achieve after the transactions.
|
|
|
|
|
|
Year Ended
|
|
December 31, 2014
|
|
(In Thousands)
|
Revenues
|
$
|
1,287,059
|
|
Depreciation, amortization, and accretion
|
$
|
160,686
|
|
Gross profit
|
$
|
122,636
|
|
|
|
Net income (loss)
|
$
|
(166,468
|
)
|
Net income (loss) attributable to TETRA stockholders
|
$
|
(174,771
|
)
|
|
|
Per share information:
|
|
|
Net income (loss) attributable to TETRA stockholders
|
|
|
Basic
|
$
|
(2.22
|
)
|
Diluted
|
$
|
(2.22
|
)
|
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
2027
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 2020
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, 2016
:
|
|
|
|
|
|
|
|
|
|
|
|
Capital Lease
|
|
Operating Leases
|
|
|
(In Thousands)
|
2017
|
|
$
|
108
|
|
|
$
|
16,455
|
|
2018
|
|
108
|
|
|
10,258
|
|
2019
|
|
108
|
|
|
7,933
|
|
2020
|
|
33
|
|
|
7,208
|
|
2021
|
|
30
|
|
|
6,814
|
|
After 2020
|
|
—
|
|
|
41,147
|
|
Total minimum lease payments
|
|
$
|
387
|
|
|
$
|
89,815
|
|
Rental expense for all operating leases was
$30.0 million
,
$37.1 million
, and
$57.4 million
in
2016
,
2015
, and
2014
, respectively.
NOTE E — INCOME TAXES
The income tax provision (benefit) attributable to continuing operations for the years ended
December 31, 2016
,
2015
,
and
2014
,
consists of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
|
|
(In Thousands)
|
Current
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
—
|
|
|
$
|
(1,310
|
)
|
|
$
|
(69
|
)
|
State
|
|
783
|
|
|
2,022
|
|
|
(195
|
)
|
Foreign
|
|
3,328
|
|
|
7,371
|
|
|
10,318
|
|
|
|
4,111
|
|
|
8,083
|
|
|
10,054
|
|
Deferred
|
|
|
|
|
|
|
|
|
|
Federal
|
|
—
|
|
|
191
|
|
|
(1,509
|
)
|
State
|
|
(610
|
)
|
|
(1,613
|
)
|
|
3,784
|
|
Foreign
|
|
(1,198
|
)
|
|
1,043
|
|
|
(2,625
|
)
|
|
|
(1,808
|
)
|
|
(379
|
)
|
|
(350
|
)
|
Total tax provision (benefit)
|
|
$
|
2,303
|
|
|
$
|
7,704
|
|
|
$
|
9,704
|
|
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,
|
|
|
2016
|
|
2015
|
|
2014
|
|
|
(In Thousands)
|
Income tax provision (benefit) computed at statutory federal income tax rates
|
|
$
|
(82,982
|
)
|
|
$
|
(70,617
|
)
|
|
$
|
(55,254
|
)
|
State income taxes (net of federal benefit)
|
|
(2,960
|
)
|
|
(608
|
)
|
|
(1,730
|
)
|
Nondeductible meals and entertainment
|
|
419
|
|
|
909
|
|
|
1,433
|
|
Impact of international operations
|
|
7,567
|
|
|
(1,880
|
)
|
|
(7,408
|
)
|
Goodwill impairments
|
|
12,990
|
|
|
20,412
|
|
|
7,442
|
|
Valuation allowance
|
|
58,846
|
|
|
55,392
|
|
|
67,781
|
|
Other
|
|
8,423
|
|
|
4,096
|
|
|
(2,560
|
)
|
Total tax provision (benefit)
|
|
$
|
2,303
|
|
|
$
|
7,704
|
|
|
$
|
9,704
|
|
Income (loss) before taxes and discontinued operations includes the following components:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
|
|
(In Thousands)
|
Domestic
|
|
$
|
(235,394
|
)
|
|
$
|
(195,815
|
)
|
|
$
|
(138,640
|
)
|
International
|
|
(1,696
|
)
|
|
(5,948
|
)
|
|
(19,231
|
)
|
Total
|
|
$
|
(237,090
|
)
|
|
$
|
(201,763
|
)
|
|
$
|
(157,871
|
)
|
A reconciliation of the beginning and ending amount of our gross unrecognized tax benefit liability is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
|
|
(In Thousands)
|
Gross unrecognized tax benefits at beginning of period
|
|
$
|
1,955
|
|
|
$
|
1,959
|
|
|
$
|
2,018
|
|
Decreases in tax positions for prior years
|
|
—
|
|
|
—
|
|
|
—
|
|
Increases in tax positions for current year
|
|
16
|
|
|
120
|
|
|
191
|
|
Lapse in statute of limitations
|
|
(378
|
)
|
|
(124
|
)
|
|
(250
|
)
|
Gross unrecognized tax benefits at end of period
|
|
$
|
1,593
|
|
|
$
|
1,955
|
|
|
$
|
1,959
|
|
We recognize interest and penalties related to uncertain tax positions in income tax expense. During the years ended
December 31, 2016
,
2015
, and
2014
, we
recognized
$(0.1) million
,
$0.3 million
, and
$0.2 million
,
respectively, of
interest and penalties to the provision for income tax. As of
December 31, 2016
and
2015
, we had
$2.3 million
and
$2.4 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
$3.2 million
and
$3.5 million
as of
December 31, 2016
and
2015
, 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
|
2010
|
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 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, 2016
and
2015
,
are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2016
|
|
2015
|
|
|
(In Thousands)
|
Net operating losses
|
|
$
|
125,358
|
|
|
$
|
91,973
|
|
Foreign tax credits and alternative minimum tax credits
|
|
28,929
|
|
|
19,772
|
|
Accruals
|
|
30,795
|
|
|
30,033
|
|
Income recognized for tax not book
|
|
1,793
|
|
|
2,608
|
|
All other
|
|
8,362
|
|
|
8,686
|
|
Total deferred tax assets
|
|
195,237
|
|
|
153,072
|
|
Valuation allowance
|
|
(185,275
|
)
|
|
(126,673
|
)
|
Net deferred tax assets
|
|
$
|
9,962
|
|
|
$
|
26,399
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2016
|
|
2015
|
|
|
(In Thousands)
|
Depreciation and amortization for tax in excess of book expense
|
|
$
|
17,012
|
|
|
$
|
34,146
|
|
All other
|
|
218
|
|
|
1,695
|
|
Total deferred tax liability
|
|
17,230
|
|
|
35,841
|
|
Net deferred tax liability
|
|
$
|
7,268
|
|
|
$
|
9,442
|
|
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,
2016
and 2015
primarily relates to
federal deferred tax assets. The increase (decrease) in the valuation allowance during the years ended
December 31, 2016
,
2015
, and
2014
, were
$58.6 million
,
$53.0 million
, and
$69.9 million
, respectively.
At
December 31, 2016
, we had approximately
$125.4 million
of
federal,
foreign, and state net operating loss carryforwards. 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
2016
through 2036. At
December 31, 2016
, we had
$28.9 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 2026. 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.
In November 2015, the FASB issued ASU 2015-17. The update changes how deferred taxes are classified on the balance sheet, eliminating the existing requirement for organizations to present deferred tax liabilities and assets as current and noncurrent in a classified balance sheet. Instead, organizations are required to classify all deferred tax assets and liabilities as noncurrent. The ASU is effective for fiscal years and interim periods within those years beginning after December 15, 2016. As permitted by ASU 2015-17, we elected to early adopt this guidance effective December 31, 2015, using the retrospective adoption. The impact of the retrospective adoption of this standard was not material to our consolidated financial statements.
NOTE F — ACCRUED LIABILITIES
Accrued liabilities are detailed as follows:
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2016
|
|
2015
|
|
|
(In Thousands)
|
Compensation and employee benefits
|
|
$
|
12,681
|
|
|
$
|
27,276
|
|
Accrued interest
|
|
9,335
|
|
|
12,723
|
|
Accrued capital expenditures
|
|
6,782
|
|
|
6,988
|
|
Accrued taxes
|
|
11,857
|
|
|
13,695
|
|
Other accrued liabilities
|
|
14,981
|
|
|
20,288
|
|
Total accrued liabilities
|
|
$
|
55,636
|
|
|
$
|
80,970
|
|
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,
2016
|
|
December 31,
2015
|
|
|
|
(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 and $1.3 million as of December 31, 2015)
|
|
September 30, 2019
|
$
|
3,229
|
|
|
$
|
21,572
|
|
5.09% Senior Notes, Series 2010-A (presented net of unamortized deferred financing costs of $0.1 million as of December 31, 2015)
|
|
December 15, 2017
|
—
|
|
|
46,809
|
|
5.67% Senior Notes, Series 2010-B (presented net of unamortized deferred financing costs of $0.1 million as of December 31, 2015)
|
|
December 15, 2020
|
—
|
|
|
17,964
|
|
4.00% Senior Notes, Series 2013 (presented net of unamortized deferred financing costs of $0.2 million as of December 31, 2015)
|
|
April 29, 2020
|
—
|
|
|
34,753
|
|
11.00% Senior Note, Series 2015 (presented net of the unamortized discount of $4.4 million as of December 31, 2016 and $4.9 million as of December 31, 2015 and net of unamortized deferred financing costs of $4.2 million as of December 31, 2016 and $3.2 million as of December 31, 2015)
|
|
November 5, 2022
|
116,411
|
|
|
116,837
|
|
Senior Secured Notes (presented net of unamortized deferred financing costs of $1.4 million as of December 31, 2015)
|
|
April 1, 2019
|
—
|
|
|
48,635
|
|
Other
|
|
|
—
|
|
|
50
|
|
TETRA total debt
|
|
|
119,640
|
|
|
286,620
|
|
Less current portion
|
|
|
—
|
|
|
(50
|
)
|
TETRA total long-term debt
|
|
|
$
|
119,640
|
|
|
$
|
286,570
|
|
|
|
|
|
|
|
CCLP
|
|
|
|
|
—
|
|
CCLP Bank Credit Facility (presented net of the unamortized deferred financing costs of $4.5 million as of December 31, 2016 and $5.4 million as of December 31, 2015)
|
|
August 4, 2019
|
217,467
|
|
|
229,555
|
|
CCLP 7.25% Senior Notes (presented net of the unamortized discount of $3.3 million as of December 31, 2016 and $4.5 million as of December 31, 2015 and net of unamortized deferred financing costs of $6.0 million as of December 31, 2016 and $8.4 million as of December 31, 2015)
|
|
August 15, 2022
|
286,623
|
|
|
337,103
|
|
CCLP total debt
|
|
|
504,090
|
|
|
566,658
|
|
Less current portion
|
|
|
—
|
|
|
—
|
|
CCLP total long-term debt
|
|
|
504,090
|
|
|
566,658
|
|
Consolidated total long-term debt
|
|
|
$
|
623,730
|
|
|
$
|
853,228
|
|
Scheduled maturities for the next five years and thereafter are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
|
|
(In Thousands)
|
|
|
TETRA
|
|
CCLP
|
|
Consolidated
|
2017
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
2018
|
|
—
|
|
|
—
|
|
|
—
|
|
2019
|
|
3,229
|
|
|
217,467
|
|
|
220,696
|
|
2020
|
|
—
|
|
|
—
|
|
|
—
|
|
2021
|
|
—
|
|
|
—
|
|
|
—
|
|
Thereafter
|
|
116,411
|
|
|
286,623
|
|
|
403,034
|
|
Total maturities
|
|
$
|
119,640
|
|
|
$
|
504,090
|
|
|
$
|
623,730
|
|
As a result of the retrospective adoption of ASU 2015-03 during the three months ended March 31, 2016, deferred financing costs of
$20.2 million
at
December 31, 2015
were reclassified out of long-term other assets and are netted against the carrying values of the bank credit facilities and senior notes of TETRA and CCLP. As of
December 31, 2016
, long-term debt is presented net of deferred financing costs of
$17.0 million
. In addition, amortization of deferred financing costs of
$4.0 million
for the year ended
December 31, 2015
were reclassified from Other Expense, net, to Interest Expense, net, in the accompanying consolidated statements of operations. As of the year ended
December 31, 2016
,
$4.1 million
of financing costs were expensed in interest expense.
As of
December 31, 2016
, TETRA (excluding CCLP) had an outstanding balance on its Credit Agreement of
$5.6 million
, and
had
$5.3 million
in letters of credit against the
revolving credit facility, leaving a net availability of
$189.2 million
. As of
December 31, 2016
, CCLP had a balance outstanding under the CCLP Credit Agreement of
$222.0 million
, had
$8.0 million
letters of credit outstanding, leaving a net availability under the CCLP Credit Agreement of
$85.0 million
. 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. In addition, as of the November 2016 amendment to the CCLP Credit Agreement, availability under the CCLP Credit Agreement is also subject to a borrowing base limitation. 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, 2016
.
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 amendment and amendment, 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 the Credit Agreement, as amended, 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. (See discussion below.) In addition, subsequent to the Fourth Amendment, borrowings will bear interest at the British Bankers Association LIBOR rate plus 2.25% to 4.00%, or an alternate base rate plus 0.00% to 1.00%, in each case dependent on our consolidated leverage ratio, and the commitment fee on unused portions of the facility will range from 0.35% to 0.75%, also dependent on our consolidated leverage ratio. 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, netting against the carrying value of the amount outstanding.
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. The Fifth Amendment provides that no consolidated leverage ratio covenant is applicable for the fiscal quarter ending December 31, 2016. 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, netting against the carrying value of the amount outstanding. 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.
The weighted average interest rate on borrowings outstanding under the Credit Agreement as of
December 31, 2016
, was
3.75%
per annum. At
December 31, 2016
, our consolidated leverage ratio was
3.47
to 1 (compared to 1.86 to1 at December 31, 2015). There is no leverage ratio requirement as of December 31, 2016 as a result of the Fifth Amendment of the Credit Agreement. Our fixed charge coverage ratio as of December 31, 2016 was
1.34
to 1 (compared to a 1.25 to 1 minimum required under the Credit Agreement).
Our Senior Notes
11% Senior Note
.
As of December 31, 2016, our senior notes consist 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"). Immediately after the closing and funding, we applied a portion of the $
119.7 million
proceeds from the sale of the 11% Senior Note (consisting of
$125.0 million
aggregate principal amount net of a
$5.0 million
discount and certain financing costs) to repay all of the indebtedness for borrowed money outstanding under our Credit Agreement. In December 2015, we applied the remaining portion of the proceeds, together with other funds to (i) pay the
$25.0 million
purchase price for 2010 Senior Notes accepted for purchase pursuant to a tender offer that commenced on November 5, 2015 (the "2015 Tender Offer"), (ii) prepay in full other senior note indebtedness, and (iii) pay other fees and expenses associated with the transactions contemplated under the 11% Senior Note Agreement.
The 11% Senior Note bears interest at the fixed rate of
11.0%
and mature 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, commencing on March 15, 2016. 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, 2016
, our consolidated funded indebtedness to EBITDA ratio was
3.47
to 1 (compared to 1.86 to 1 at December 31, 2015). There is no consolidated funded indebtedness ratio requirement as of December 31, 2016 as a result of the Amended and Restated 11% Senior Note Agreement. At December 31, 2016, our fixed charge coverage ratio was
1.34
to 1 (compared to a 1.25 minimum required under the Amended and Restated 11% Senior Note Agreement).
Other Senior Notes
.
In April 2015, we utilized the proceeds from the issuance of the Senior Secured Notes (see discussion below) along with borrowings under our Credit Agreement to repay other senior note indebtedness. In December 2015, we prepaid in full all amounts owed in respect of the outstanding Series 2006-A Senior Notes, due April 30, 2016, including a $1.6 million "make-whole" prepayment premium in accordance with the Master Note Purchase Agreement. This "make-whole" prepayment premium was charged to Other Expense in the accompanying statement of operations.
In December 2015, and pursuant to a tender offer that commenced on
November 5, 2015
(the "2015 Tender Offer"), we purchased for cash
$25.0 million
aggregate principal amount of certain of the outstanding 2010 Senior Notes, consisting of $
18.1 million
of the Series 2010-A Senior Notes and $
6.9 million
of the Series 2010-B Senior Notes. The offered consideration for 2010 Senior Notes was an amount of cash equal to $100,000 per $100,000 principal amount of 2010 Senior Notes tendered prior to December 7, 2015, and accepted for purchase by us, plus accrued and unpaid interest.
In May 2016, and pursuant to tender offers (the “2016 Tender Offers”) to purchase for cash any and all of the outstanding Series 2010-A Senior Notes, Series 2010-B Senior Notes, and Series 2013 Senior Notes (together the "Tender Offer Senior Notes"), we purchased Tender Offer Senior Notes in an aggregate principal amount of
$100.0 million
, representing the total outstanding principal amount of the Tender Offer Senior Notes.
On April 30, 2015, we issued and sold
$50.0 million
aggregate principal amount of Senior Secured Notes due
April 1, 2017
(the "Senior Secured Notes"). On November 5, 2015, we entered into the Second Amendment
(the “Second Amendment”) to the Note Purchase Agreement that, conditioned upon the closing and funding of the issuance of the 11% Senior Note, (i) provided for the extension of the maturity date of the Senior Secured Notes from
April 1, 2017
to
April 1, 2019
, (ii) amended certain definitions in the Note Purchase Agreement and (iii) required us to pay an extension fee. Prior to June 2016, we repaid an aggregate principal amount of $20.0 million of the amount outstanding under the Senior Secured Notes. In June 2016, and following the issuance of
11.5 million
shares of our common stock, we utilized a portion of the
$60.4 million
of net proceeds to repay the remaining
$30.0 million
outstanding under our Senior Secured Notes. See Note K - "Capital Stock" for further discussion of stock issuances during 2016. In connection with the repayment of the Senior Secured Notes,
$1.1 million
of remaining unamortized deferred finance costs were charged to Other Expense during the year ended December 31, 2016.
CCLP Long-Term Debt
CCLP Bank Credit Facility
CCLP Credit Agreement
.
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, which matures on August 4, 2019, 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. During the year ended December 31, 2014, CCLP incurred financing costs of approximately
$7.0 million
related to the CCLP Credit Agreement. These costs are being amortized over the term of the CCLP Credit Agreement. Also during 2014, approximately
$0.8 million
of unamortized deferred financing costs associated with the previous CCLP credit agreement was charged to interest expense.
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
$0.7 million
were charged to interest expense during the year ended December 31, 2016. Pursuant to the CCLP Third Amendment, bank fees of
$0.7 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. The CCLP Fourth Amendment modified certain covenants as follows: (i) the consolidated total leverage ratio may not exceed (a) 5.75 to 1 as of September 30, 2016, (b) 5.95 to 1 as of the fiscal quarters ended December 31, 2016 through June 30, 2018; (c) 5.75 to 1 as of September 30, 2018 and December 31, 2018; and (d) 5.50 to 1 as of March 31, 2019 and thereafter; (ii) the consolidated secured leverage ratio may not exceed (a) 3.25 to 1 as of the fiscal quarters ended September 30, 2016 through June 30, 2018; and (b) 3.50 to 1 as of September 30, 2018 and thereafter; and (iii) the consolidated interest coverage ratio may not fall below (a) 2.25 to 1 as of the fiscal quarters ended September 30, 2016 through June 30, 2018; (b) 2.50 to 1 as of September 30, 2018 and December 31, 2018; and (c) 2.75 to 1 as of March 31, 2019 and thereafter. In addition, the CCLP Fourth Amendment reduced the maximum aggregate lender commitments from $340.0 million to $315.0 million. The CCLP Fourth Amendment provides for an increase in the applicable margin by 0.25% in the event the consolidated leverage ratio exceeds 5.50 to 1, resulting in a range for the applicable margin between 2.00% and 3.25% per annum for LIBOR-based loans and 1.00% to 2.25% per annum for base-rate loans, according to the consolidated total leverage ratio. 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.
The weighted average interest rate on borrowings outstanding under the CCLP Credit Agreement as of
December 31, 2016
, was
3.45%
per annum. At
December 31, 2016
, CCLP's consolidated total leverage ratio was
5.40
to 1 (compared to 5.95 to 1 maximum allowed under the CCLP Credit Agreement), its consolidated secured leverage ratio was
2.35
to 1 (compared to 3.25 to 1 maximum allowed under the CCLP Credit Agreement), and its consolidated interest coverage ratio was
3.13
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 7.25% Senior Notes
The obligations under the 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.
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. Following the repurchase of these CCLP 7.25% Senior Notes, $295.9 million aggregate principal amount of CCLP 7.25% Senior Notes remain outstanding. 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) of 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 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
. The net proceeds from the Initial Private Placement and Subsequent Private Placement were used to pay additional offering expenses and reduce outstanding CCLP indebtedness under the CCLP Credit Agreement and the CCLP 7.25% Senior Notes.
In connection with the closing of the Initial Private Placement, CSI Compressco GP Inc (our wholly owned subsidiary) executed a Second Amended and Restated Agreement of Limited Partnership of CCLP (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 will rank senior to all classes or series of equity securities of CCLP with respect to distribution rights and rights upon liquidation. We and the other holders of CCLP Preferred Units (each, a “CCLP Preferred Unitholder”) will receive quarterly distributions, which will be 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, divided by the
$11.43
Issue Price. 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 will be converted into CCLP common units on the eighth day of each month over a period of thirty months beginning 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, the CCLP Preferred Units will convert into 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 previous month, among other factors, and as otherwise impacted by the existence of certain conditions related to the common units. The maximum aggregate number of common units that could be required to be issued pursuant to the conversion provisions of the Preferred Units is potentially unlimited; 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.
In addition, each purchaser may convert its CCLP Preferred Units, generally on a one-for-one basis and subject to adjustment for certain splits, combinations, reclassifications or other similar transactions and certain anti-
dilution adjustments, in whole or in part, at any time following May 31, 2017 so long as any conversion is not for less than $250,000 or such lesser amount, if such conversion relates to all of such purchaser’s remaining CCLP Preferred Units. CCLP has the right to be reimbursed for any cash distributions paid with respect to common units issued in any such optional conversion until March 31, 2018. The CCLP Preferred Units will vote on an as-converted basis with the common units and will have certain other rights to vote as a class with respect to any amendment to the Amended and Restated CCLP Partnership Agreement that would affect any rights, preferences or privileges of the CCLP Preferred Units, as more fully described in the Amended and Restated CCLP Partnership Agreement.
Because the Preferred Units may be settled using a variable number of common units, the fair value of the 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, 2016
was
$77.1 million
. Changes in the fair value during each quarterly period, including the
$4.4 million
increase in fair value during 2016 subsequent to the issuance of the CCLP Preferred Units, are charged to other expense in the accompanying consolidated statements of operations. Based on the conversion provisions of the Preferred Units, and using the Conversion Price calculated as of
December 31, 2016
, the theoretical number of CCLP common units that would be issued if all of the CCLP Preferred Units were settled as of
December 31, 2016
would be approximately
8.7 million
common units, with an aggregate market value of
$84.5 million
. A $1 decrease in the average trading price per CCLP common unit would result in the issuance of approximately
1.0 million
additional common units pursuant to these conversion provisions.
In addition, the CCLP Unit Purchase Agreements include certain provisions regarding change of control, transfer of CCLP Preferred Units, indemnities, and other matters described in detail in the respective CCLP Unit Purchase Agreement. In connection with the closings of the Initial and Subsequent Private Placements, CCLP paid total transaction fees of
$2.1 million
to its financial advisors for these transactions. These transaction fees were charged to Other (Income) Expense in the accompanying consolidated statements of operations. The CCLP Unit Purchase Agreements contain customary representations, warranties and covenants of CCLP and the purchasers.
NOTE
I
– DECOMMISSIONING AND OTHER ASSET RETIREMENT OBLIGATIONS
The large majority of our asset retirement obligations 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. 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 our asset retirement obligations for non-Maritech properties were approximately
$9.4 million
and
$9.1 million
as of
December 31, 2016
and
2015
, 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,
|
|
|
2016
|
|
2015
|
|
|
(In Thousands)
|
Beginning balance for the period, as reported
|
|
$
|
57,449
|
|
|
$
|
62,741
|
|
Activity in the period:
|
|
|
|
|
|
|
Accretion of liability
|
|
2,249
|
|
|
2,000
|
|
Retirement obligations incurred
|
|
—
|
|
|
—
|
|
Revisions in estimated cash flows
|
|
(180
|
)
|
|
3,341
|
|
Settlement of retirement obligations
|
|
(4,040
|
)
|
|
(10,633
|
)
|
Ending balance
|
|
$
|
55,478
|
|
|
$
|
57,449
|
|
We review the adequacy of our decommissioning liabilities whenever indicators suggest that the estimated cash flows underlying the liabilities have changed. For our Maritech segment, the timing and amounts of these cash flows are subject to changes in the oil and gas industry environment and other factors and may result in additional liabilities to be recorded. We increased the estimated cash flows to
decommission these properties by approximately
$3.3 million
in
2015
and approximately
$2.6 million
of this amount was charged to cost of product sales during 2015.
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
$7.9 million
and has been accrued as part of Maritech’s decommissioning liabilities as of
December 31, 2016
.
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. During
2014
, Maritech added new decommissioning liabilities for remediation work required on projects previously thought to be completed
of approximately
$39.2 million
for work performed during the year or related to the estimated cost of future work to be performed. This additional amount was directly charged to earnings as an operating expense during 2014. Maritech is the last operator of record for its plugged wells, and bears the risk of additional future work required as a result of wells becoming pressurized in the future.
These increased estimates are included in the revisions in estimated cash flows in the table above.
A
portion of the excess decommissioning costs recorded during
2015
was associated with properties not operated by Maritech and also include additional work incurred and anticipated to be required, including remediation work required on certain wells that had been previously plugged.
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, 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, we initiated arbitration proceedings 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 such amount was recorded in earnings during the first quarter of 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, 2016
, the aggregate amount of the fixed and determinable portion of the purchase obligation pursuant to our Fluids Division’s supply agreements was
approximately
$127.1 million
, including
$13.6 million
during
2017
,
$9.5 million
during
2018
,
$9.5 million
during
2019
,
$9.5 million
during
2020
,
$9.5 million
during
2021
, and
$75.6 million
thereafter, extending through 2029. Amounts purchased under these agreements for each of the years ended
December 31, 2016
,
2015
,
and
2014
,
was
$13.3 million
,
$22.0 million
, and
$21.6 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. 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 current oil and natural gas pricing levels continue, we expect that one or more of these buyers may be unable to perform the decommissioning work required on the properties acquired from Maritech.
During 2015 and 2016, continued low oil and natural gas prices have resulted in reduced revenues and cash flows for all oil and gas producing companies, including those companies that bought Maritech properties in the past. Certain of these 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 monitor the status of these companies. As of
December 31, 2016
, we do not consider the likelihood of Maritech becoming liable for decommissioning liabilities on sold properties to be probable.
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 bears the risk of additional future work required as a result of wells becoming pressurized in the future.
NOTE K — CAPITAL STOCK AND WARRANTS
Our Restated Certificate of Incorporation, as amended during 2016, authorizes us to issue
150,000,000
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, 2016
, we had
114,985,072
shares of common stock outstanding, with
2,865,991
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 our 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, 2016, 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 an initial fair value of
$16.4 million
, with changes in fair value included in Other Expense in the period of change. As of
December 31, 2016
, the fair value of the Warrants was
$18.5 million
, and the
$2.1 million
change in fair value was charged to earnings during the period. 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, 2016
, is as follows:
|
|
|
|
|
|
|
|
|
|
|
Common Shares Outstanding
|
|
Year Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
At beginning of period
|
|
80,256,544
|
|
|
79,649,946
|
|
|
78,855,547
|
|
Exercise of common stock options, net
|
|
636,937
|
|
|
67,808
|
|
|
290,369
|
|
Grants of restricted stock, net
|
|
281,591
|
|
|
538,790
|
|
|
504,030
|
|
Issuance of common stock
|
|
33,810,000
|
|
|
—
|
|
|
—
|
|
At end of period
|
|
114,985,072
|
|
|
80,256,544
|
|
|
79,649,946
|
|
|
|
|
|
|
|
|
|
|
|
|
Treasury Shares Held
|
|
Year Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
At beginning of period
|
|
2,767,084
|
|
|
2,672,930
|
|
|
2,478,084
|
|
Shares received upon exercise of common stock options
|
|
13,854
|
|
|
36,818
|
|
|
189,469
|
|
Shares received upon vesting of restricted stock, net
|
|
85,053
|
|
|
57,336
|
|
|
5,377
|
|
At end of period
|
|
2,865,991
|
|
|
2,767,084
|
|
|
2,672,930
|
|
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, 2016
, 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, 2016
,
2015
, and
2014
, was
$13.7 million
,
$16.9 million
, and
$6.8 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, 2016
,
2015
, and
2014
,
was
$9.5 million
,
$13.9 million
, and
$4.7 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, 2016
, 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, 2016
:
|
|
|
|
|
|
|
|
|
|
|
Units
|
|
Weighted Average
Grant Date Fair
Value Per Unit
|
|
|
(In Thousands)
|
|
|
Nonvested units outstanding at December 31, 2015
(1)
|
|
309
|
|
|
$
|
21.77
|
|
Units granted
(1)
|
|
397
|
|
|
8.34
|
|
Units cancelled
|
|
(74
|
)
|
|
20.07
|
|
Units vested
|
|
(23
|
)
|
|
17.07
|
|
Nonvested units outstanding at December 31, 2016
(2)
|
|
609
|
|
|
$
|
13.41
|
|
|
|
(1)
|
The number of units granted shown above excludes
91,832
performance-based phantom units, which represents the maximum 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
216,849
performance-based phantom units, which, when combined with the
289,830
granted, 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
433,698
.
Stock Options
The weighted average fair value of options granted during the years ended
December 31, 2016
,
2015
, and
2014
,
was
$3.16
,
$3.17
, and
$4.07
, respectively, using the Black-Scholes option valuation model with the following weighted average assumptions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
Expected stock price volatility
|
|
52%
|
|
|
49% to 51%
|
|
|
44% to 45%
|
|
Expected life of options
|
|
4.6 years
|
|
|
4.6 years
|
|
|
4.9 years
|
|
Risk free interest rate
|
|
1.2%
|
|
|
1.41% to 1.51%
|
|
|
.01%
|
|
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, 2016
,
2015
and
2014
, 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, 2016
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2016
|
|
4,167
|
|
|
$
|
11.23
|
|
|
|
|
|
Options granted
|
|
851
|
|
|
7.14
|
|
|
|
|
|
Options cancelled
|
|
(383
|
)
|
|
9.25
|
|
|
|
|
|
Options exercised
|
|
(28
|
)
|
|
4.07
|
|
|
|
|
|
Options expired
|
|
(220
|
)
|
|
$
|
28.00
|
|
|
|
|
|
Outstanding at December 31, 2016
|
|
4,387
|
|
|
$
|
9.81
|
|
|
5.8
|
|
$
|
629
|
|
Expected to vest at December 31, 2016
|
|
4,293
|
|
|
$
|
9.87
|
|
|
5.7
|
|
$
|
629
|
|
Exercisable at December 31, 2016
|
|
3,214
|
|
|
$
|
10.71
|
|
|
4.7
|
|
$
|
629
|
|
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, 2016
,
2015
, and
2014
,
was
approximately
$0.1 million
,
$0.2 million
,
and
$1.4 million
, respectively.
At
December 31, 2016
, total unrecognized compensation cost related to unvested stock options of
$2.8 million
, is expected to be recognized over a weighted-average remaining service period of
1.82
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, 2016
:
|
|
|
|
|
|
|
|
|
|
|
Shares
|
|
Weighted Average
Grant Date Fair
Value Per Share
|
|
|
(In Thousands)
|
|
|
Nonvested restricted shares outstanding at December 31, 2015
|
|
878
|
|
|
$
|
8.54
|
|
Granted
|
|
1,226
|
|
|
6.31
|
|
Vested
|
|
(1,205
|
)
|
|
6.97
|
|
Cancelled/Forfeited
|
|
(94
|
)
|
|
7.08
|
|
Nonvested restricted shares outstanding at December 31, 2016
|
|
805
|
|
|
$
|
7.65
|
|
Total compensation cost recognized for restricted stock awards was
$8.4 million
,
$5.4 million
, and
$4.1 million
for the years ended
December 31, 2016
,
2015
, and
2014
respectively. Total unrecognized compensation cost at
December 31, 2016
, related to restricted stock awards is approximately
$4.2 million
which is expected to be recognized over a weighted-average remaining amortization period of
1.8
years. During the years ended
December 31, 2016
,
2015
, and
2014
, the total fair value of shares vested was
$8.4 million
,
$4.8 million
and
$4.3 million
, respectively.
During
2016
,
2015
, and
2014
, we
received
254,858
,
57,336
and
56,071
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, 2016
, net of options previously exercised pursuant to our various
equity compensation
plans, we have a maximum of
10,267,381
shares of common stock issuable pursuant to
awards
previously granted and outstanding and
awards
authorized to be granted in the future.
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 to be determined. 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
$1.4 million
,
$4.2 million
, and
$4.4 million
in
2016
,
2015
, and
2014
, 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-six
participants in the program at
December 31, 2016
. 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, 2016
, 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
$18.5 million
as of December 31, 2016, and is classified as Warrant Liability, a long-term liability, on the consolidated balance sheet. Changes in the fair value of the Warrants from the issuance date to December 31, 2016 was
$2.1 million
and are 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, 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
|
As of
December 31, 2015
, 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
|
|
$
|
3,768
|
|
|
1.11
|
|
1/19/2016
|
Forward purchase pounds sterling
|
|
$
|
12,614
|
|
|
1.52
|
|
1/19/2016
|
Forward purchase Mexican peso
|
|
$
|
7,850
|
|
|
17.45
|
|
1/19/2016
|
Forward purchase Saudi Arabia riyal
|
|
$
|
5,040
|
|
|
3.74
|
|
1/5/2016
|
Forward sale Mexican peso
|
|
$
|
4,641
|
|
|
17.45
|
|
1/19/2016
|
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 measurement). The fair values of our foreign currency derivative instruments as of
December 31, 2016
and
2015
, are as follows:
|
|
|
|
|
|
|
|
|
|
|
Foreign currency derivative instruments
|
Balance Sheet Location
|
|
Fair Value at
December 31, 2016
|
Fair Value at
December 31, 2015
|
|
|
|
|
(In Thousands)
|
Forward purchase contracts
|
|
Current assets
|
|
$
|
—
|
|
$
|
—
|
|
Forward sale contracts
|
|
Current assets
|
|
81
|
|
23
|
|
Forward sale contracts
|
|
Current liabilities
|
|
—
|
|
(31
|
)
|
Forward purchase contracts
|
|
Current liabilities
|
|
(371
|
)
|
(354
|
)
|
Total
|
|
|
|
$
|
(290
|
)
|
$
|
(362
|
)
|
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, 2016
,
2015
, and
2014
, we recognized approximately $
2.0 million
,
$0.6 million
and
$1.9 million
of net losses reflected in other expense 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,
|
|
|
2016
|
|
2015
|
|
2014
|
|
|
(In Thousands)
|
Number of weighted average common shares outstanding
|
|
87,286
|
|
|
79,169
|
|
|
78,600
|
|
Assumed exercise of stock options
|
|
—
|
|
|
—
|
|
|
—
|
|
Average diluted shares outstanding
|
|
87,286
|
|
|
79,169
|
|
|
78,600
|
|
For the year
ended
December 31, 2016
, the average diluted shares outstanding excludes the impact of all outstanding stock options 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 year ended
December 31, 2016
, 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. For the year
ended
December 31, 2015
, the average diluted shares outstanding excludes the impact of all outstanding stock options, as the inclusion of these shares would have been antidilutive due to the net loss recorded during the year.
For the year ended
December 31, 2014
, the average diluted shares outstanding excludes the impact of all outstanding stock options, as the inclusion of these shares would have been antidilutive due to the net loss recorded during the year.
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 in many of the major oil and gas producing regions in the United States, Mexico, and Canada, as well as in basins in certain regions in South America, Africa, Europe, the Middle East, and Australia.
The 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. As a result of the August 4, 2014 acquisition of CSI, the scope of our Compression Division was significantly expanded.
Our Offshore Division consists of
two
operating segments: Offshore Services and Maritech. The Offshore Services segment provides (1) downhole and subsea services such as well plugging and abandonment and workover 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 is 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 consist primarily of the ongoing abandonment and decommissioning associated with its remaining offshore wells and production platforms. Maritech intends to acquire a portion of these services from the Offshore Services segment.
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:
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
|
|
(In Thousands)
|
Revenues from external customers
|
|
|
|
|
|
|
|
|
|
Product sales
|
|
|
|
|
|
|
|
|
|
Fluids Division
|
|
$
|
176,882
|
|
|
$
|
306,307
|
|
|
$
|
294,895
|
|
Production Testing Division
|
|
—
|
|
|
6,944
|
|
|
—
|
|
Compression Division
|
|
71,809
|
|
|
141,461
|
|
|
74,827
|
|
Offshore Division
|
|
|
|
|
|
|
|
|
|
Offshore Services
|
|
116
|
|
|
611
|
|
|
534
|
|
Maritech
|
|
751
|
|
|
2,438
|
|
|
4,722
|
|
Total Offshore Division
|
|
867
|
|
|
3,049
|
|
|
5,256
|
|
Consolidated
|
|
$
|
249,558
|
|
|
$
|
457,761
|
|
|
$
|
374,978
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Services and rentals
|
|
|
|
|
|
|
|
|
|
Fluids Division
|
|
$
|
69,625
|
|
|
$
|
117,459
|
|
|
$
|
142,139
|
|
Production Testing Division
|
|
59,509
|
|
|
122,292
|
|
|
188,528
|
|
Compression Division
|
|
239,566
|
|
|
316,178
|
|
|
207,679
|
|
Offshore Division
|
|
|
|
|
|
|
|
|
|
Offshore Services
|
|
76,506
|
|
|
116,455
|
|
|
164,243
|
|
Maritech
|
|
|
|
|
—
|
|
|
—
|
|
Intersegment eliminations
|
|
—
|
|
|
—
|
|
|
—
|
|
Total Offshore Division
|
|
76,506
|
|
|
116,455
|
|
|
164,243
|
|
Corporate overhead
|
|
—
|
|
|
—
|
|
|
—
|
|
Consolidated
|
|
$
|
445,206
|
|
|
$
|
672,384
|
|
|
$
|
702,589
|
|
|
|
|
|
|
|
|
Interdivision revenues
|
|
|
|
|
|
|
|
|
Fluids Division
|
|
$
|
87
|
|
|
$
|
278
|
|
|
$
|
327
|
|
Production Testing Division
|
|
4,109
|
|
|
4,668
|
|
|
4,296
|
|
Compression Division
|
|
—
|
|
|
—
|
|
|
—
|
|
Offshore Division
|
|
|
|
|
|
|
|
|
|
Offshore Services
|
|
903
|
|
|
5,128
|
|
|
30,595
|
|
Maritech
|
|
—
|
|
|
—
|
|
|
—
|
|
Intersegment eliminations
|
|
(903
|
)
|
|
(5,128
|
)
|
|
(30,595
|
)
|
Total Offshore Division
|
|
—
|
|
|
—
|
|
|
—
|
|
Interdivision eliminations
|
|
(4,196
|
)
|
|
(4,946
|
)
|
|
(4,623
|
)
|
Consolidated
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fluids Division
|
|
$
|
246,595
|
|
|
$
|
424,044
|
|
|
$
|
437,362
|
|
Production Testing Division
|
|
63,618
|
|
|
133,904
|
|
|
192,824
|
|
Compression Division
|
|
311,374
|
|
|
457,639
|
|
|
282,505
|
|
Offshore Division
|
|
|
|
|
|
|
|
|
|
Offshore Services
|
|
77,525
|
|
|
122,194
|
|
|
195,372
|
|
Maritech
|
|
751
|
|
|
2,438
|
|
|
4,722
|
|
Intersegment eliminations
|
|
(903
|
)
|
|
(5,128
|
)
|
|
(30,595
|
)
|
Total Offshore Division
|
|
77,373
|
|
|
119,504
|
|
|
169,499
|
|
Corporate overhead
|
|
—
|
|
|
—
|
|
|
—
|
|
Interdivision eliminations
|
|
(4,196
|
)
|
|
(4,946
|
)
|
|
(4,623
|
)
|
Consolidated
|
|
$
|
694,764
|
|
|
$
|
1,130,145
|
|
|
$
|
1,077,567
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
|
|
(In Thousands)
|
Depreciation, amortization, and accretion
|
|
|
|
|
|
|
|
|
|
Fluids Division
|
|
$
|
28,338
|
|
|
$
|
35,125
|
|
|
$
|
31,279
|
|
Production Testing Division
|
|
16,221
|
|
|
24,080
|
|
|
29,324
|
|
Compression Division
|
|
72,159
|
|
|
82,024
|
|
|
41,097
|
|
Offshore Division
|
|
|
|
|
|
|
|
|
Offshore Services
|
|
11,086
|
|
|
11,500
|
|
|
13,327
|
|
Maritech
|
|
1,362
|
|
|
1,375
|
|
|
160
|
|
Intersegment eliminations
|
|
—
|
|
|
—
|
|
|
—
|
|
Total Offshore Division
|
|
12,448
|
|
|
12,875
|
|
|
13,487
|
|
Corporate overhead
|
|
429
|
|
|
911
|
|
|
1,725
|
|
Consolidated
|
|
$
|
129,595
|
|
|
$
|
155,015
|
|
|
$
|
116,912
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
|
|
|
|
|
|
|
Fluids Division
|
|
$
|
32
|
|
|
$
|
22
|
|
|
$
|
21
|
|
Production Testing Division
|
|
42
|
|
|
—
|
|
|
29
|
|
Compression Division
|
|
38,271
|
|
|
35,235
|
|
|
15,562
|
|
Offshore Division
|
|
|
|
|
|
|
|
|
|
Offshore Services
|
|
—
|
|
|
—
|
|
|
36
|
|
Maritech
|
|
12
|
|
|
29
|
|
|
—
|
|
Intersegment eliminations
|
|
—
|
|
|
—
|
|
|
—
|
|
Total Offshore Division
|
|
12
|
|
|
29
|
|
|
36
|
|
Corporate overhead
|
|
21,639
|
|
|
19,879
|
|
|
20,063
|
|
Consolidated
|
|
$
|
59,996
|
|
|
$
|
55,165
|
|
|
$
|
35,711
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
|
|
(In Thousands)
|
Income (loss) before taxes
|
|
|
|
|
|
|
|
|
|
Fluids Division
|
|
$
|
10,430
|
|
|
$
|
80,789
|
|
|
$
|
64,705
|
|
Production Testing Division
|
|
(35,471
|
)
|
|
(55,720
|
)
|
|
(66,156
|
)
|
Compression Division
|
|
(136,327
|
)
|
|
(146,798
|
)
|
|
7,340
|
|
Offshore Division
|
|
|
|
|
|
|
|
|
|
Offshore Services
|
|
(12,025
|
)
|
|
(195
|
)
|
|
(26,251
|
)
|
Maritech
|
|
(1,841
|
)
|
|
(3,833
|
)
|
|
(71,154
|
)
|
Intersegment eliminations
|
|
—
|
|
|
—
|
|
|
—
|
|
Total Offshore Division
|
|
(13,866
|
)
|
|
(4,028
|
)
|
|
(97,405
|
)
|
Interdivision eliminations
|
|
7
|
|
|
(1
|
)
|
|
—
|
|
Corporate overhead
(1)
|
|
(61,864
|
)
|
|
(76,005
|
)
|
|
(66,355
|
)
|
Consolidated
|
|
$
|
(237,090
|
)
|
|
$
|
(201,763
|
)
|
|
$
|
(157,871
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
|
|
(In Thousands)
|
Total assets
|
|
|
|
|
|
|
|
|
|
Fluids Division
|
|
$
|
322,858
|
|
|
$
|
370,892
|
|
|
$
|
423,989
|
|
Production Testing Division
|
|
87,462
|
|
|
134,725
|
|
|
241,640
|
|
Compression Division
|
|
816,148
|
|
|
1,004,760
|
|
|
1,256,970
|
|
Offshore Division
|
|
|
|
|
|
|
|
|
|
Offshore Services
|
|
102,715
|
|
|
131,916
|
|
|
129,350
|
|
Maritech
|
|
3,660
|
|
|
18,453
|
|
|
23,479
|
|
Intersegment eliminations
|
|
—
|
|
|
—
|
|
|
—
|
|
Total Offshore Division
|
|
106,375
|
|
|
150,369
|
|
|
152,829
|
|
Corporate overhead and eliminations
|
|
(17,303
|
)
|
|
(24,544
|
)
|
|
(11,906
|
)
|
Consolidated
|
|
$
|
1,315,540
|
|
|
$
|
1,636,202
|
|
|
$
|
2,063,522
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
|
|
|
|
|
|
|
Fluids Division
|
|
$
|
2,311
|
|
|
$
|
11,104
|
|
|
$
|
41,307
|
|
Production Testing Division
|
|
802
|
|
|
7,843
|
|
|
31,226
|
|
Compression Division
|
|
11,568
|
|
|
95,586
|
|
|
37,516
|
|
Offshore Division
|
|
|
|
|
|
|
|
|
|
Offshore Services
|
|
5,913
|
|
|
5,949
|
|
|
20,013
|
|
Maritech
|
|
—
|
|
|
38
|
|
|
—
|
|
Intersegment eliminations
|
|
—
|
|
|
—
|
|
|
—
|
|
Total Offshore Division
|
|
5,913
|
|
|
5,987
|
|
|
20,013
|
|
Corporate overhead
|
|
472
|
|
|
77
|
|
|
1,547
|
|
Consolidated
|
|
$
|
21,066
|
|
|
$
|
120,597
|
|
|
$
|
131,609
|
|
|
|
(1)
|
Amounts reflected include the following general corporate expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2015
|
|
2014
|
|
|
(In Thousands)
|
General and administrative expense
|
|
$
|
34,767
|
|
|
$
|
52,189
|
|
|
$
|
41,139
|
|
Depreciation and amortization
|
|
430
|
|
|
913
|
|
|
1,725
|
|
Interest expense, net
|
|
21,157
|
|
|
18,654
|
|
|
19,268
|
|
Other general corporate (income) expense, net
|
|
5,510
|
|
|
4,249
|
|
|
4,223
|
|
Total
|
|
$
|
61,864
|
|
|
$
|
76,005
|
|
|
$
|
66,355
|
|
Summarized financial information concerning the geographic areas of our customers and in which we operate at
December 31, 2016
,
2015
, and
2014
,
is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
|
|
(In Thousands)
|
Revenues from external customers:
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
$
|
535,613
|
|
|
$
|
896,131
|
|
|
$
|
768,688
|
|
Canada and Mexico
|
|
34,560
|
|
|
44,542
|
|
|
73,632
|
|
South America
|
|
20,480
|
|
|
26,554
|
|
|
40,719
|
|
Europe
|
|
71,882
|
|
|
80,432
|
|
|
105,457
|
|
Africa
|
|
10,345
|
|
|
20,761
|
|
|
22,277
|
|
Asia and other
|
|
21,884
|
|
|
61,725
|
|
|
66,794
|
|
Total
|
|
$
|
694,764
|
|
|
$
|
1,130,145
|
|
|
$
|
1,077,567
|
|
Transfers between geographic areas:
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Canada and Mexico
|
|
—
|
|
|
—
|
|
|
—
|
|
South America
|
|
—
|
|
|
—
|
|
|
—
|
|
Europe
|
|
93
|
|
|
1,252
|
|
|
2,871
|
|
Africa
|
|
—
|
|
|
—
|
|
|
—
|
|
Asia and other
|
|
—
|
|
|
—
|
|
|
—
|
|
Eliminations
|
|
(93
|
)
|
|
(1,252
|
)
|
|
(2,871
|
)
|
Total revenues
|
|
$
|
694,764
|
|
|
$
|
1,130,145
|
|
|
$
|
1,077,567
|
|
Identifiable assets:
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
$
|
1,132,986
|
|
|
$
|
1,403,916
|
|
|
$
|
1,759,491
|
|
Canada and Mexico
|
|
64,163
|
|
|
74,260
|
|
|
97,737
|
|
South America
|
|
21,354
|
|
|
25,603
|
|
|
32,267
|
|
Europe
|
|
53,713
|
|
|
64,695
|
|
|
94,209
|
|
Africa
|
|
5,711
|
|
|
7,542
|
|
|
7,895
|
|
Asia and other
|
|
37,613
|
|
|
60,186
|
|
|
71,923
|
|
Eliminations
|
|
—
|
|
|
—
|
|
|
—
|
|
Total identifiable assets
|
|
$
|
1,315,540
|
|
|
$
|
1,636,202
|
|
|
$
|
2,063,522
|
|
During each of the three years ended
December 31, 2016
,
2015
, and
2014
, 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. Maritech's current operations consist 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, 2016
.
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,
|
|
|
2016
|
|
2015
|
|
2014
|
|
|
(In Thousands)
|
Oil and gas sales revenues
|
|
$
|
751
|
|
|
$
|
2,438
|
|
|
$
|
4,722
|
|
Production (lifting) costs
|
|
643
|
|
|
921
|
|
|
2,002
|
|
Depreciation, depletion, and amortization
|
|
—
|
|
|
—
|
|
|
30
|
|
Excess decommissioning and abandonment costs
|
|
2,593
|
|
|
2,665
|
|
|
73,194
|
|
Accretion expense
|
|
1,362
|
|
|
1,375
|
|
|
130
|
|
Gain on insurance recoveries
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
Pretax income (loss) from producing activities
|
|
(3,847
|
)
|
|
(2,523
|
)
|
|
(70,628
|
)
|
Income tax expense (benefit)
|
|
—
|
|
|
—
|
|
|
—
|
|
Results of oil and gas producing activities
|
|
$
|
(3,847
|
)
|
|
$
|
(2,523
|
)
|
|
$
|
(70,628
|
)
|
NOTE S — QUARTERLY FINANCIAL INFORMATION (Unaudited)
Summarized quarterly financial data for
2016
and
2015
is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 income loss per diluted share attributable to TETRA stockholders
|
|
$
|
(1.11
|
)
|
|
$
|
(0.32
|
)
|
|
$
|
(0.16
|
)
|
|
$
|
(0.33
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended 2015
|
|
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
|
|
(In Thousands, Except Per Share Amounts)
|
Total revenues
|
|
$
|
251,092
|
|
|
$
|
316,319
|
|
|
$
|
305,144
|
|
|
$
|
257,590
|
|
Gross profit
|
|
46,087
|
|
|
69,861
|
|
|
70,534
|
|
|
2,755
|
|
Net income (loss)
|
|
(3,622
|
)
|
|
15,367
|
|
|
10,736
|
|
|
(231,946
|
)
|
Net income (loss) attributable to TETRA stockholders
|
|
(4,447
|
)
|
|
14,925
|
|
|
9,755
|
|
|
(146,415
|
)
|
Net income (loss) per share attributable to TETRA stockholders
|
|
$
|
(0.06
|
)
|
|
$
|
0.19
|
|
|
$
|
0.12
|
|
|
$
|
(1.84
|
)
|
Net income (loss) per diluted share attributable to TETRA stockholders
|
|
$
|
(0.06
|
)
|
|
$
|
0.19
|
|
|
$
|
0.12
|
|
|
$
|
(1.84
|
)
|
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.
Gross profit (loss) for the three months ended
December 31, 2015
, includes the impact of
$44.2 million
for certain impairments of long-lived assets, and net loss for this period includes the additional impact of
$177.0 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,
|
|
2016
|
|
2015
|
Assets
|
|
|
|
Current Assets
|
|
|
|
Accounts receivable
|
$
|
35,058
|
|
|
$
|
54,187
|
|
Inventories
|
44,765
|
|
|
39,766
|
|
Prepaid expenses
|
2,091
|
|
|
4,903
|
|
Other current assets
|
5,680
|
|
|
6,055
|
|
Total current assets
|
87,594
|
|
|
104,911
|
|
Property, plant and equipment
|
341,985
|
|
|
346,622
|
|
Less accumulated depreciation
|
(188,268
|
)
|
|
(171,931
|
)
|
Property, plant, and equipment, net
|
153,717
|
|
|
174,691
|
|
Other assets, including investment in and amounts due from wholly owned subsidiaries
|
833,395
|
|
|
935,742
|
|
Total assets
|
1,074,706
|
|
|
1,215,344
|
|
|
|
|
|
Liabilities and stockholders' equity
|
|
|
|
|
|
Current liabilities
|
32,999
|
|
|
57,162
|
|
Long-term debt
|
119,640
|
|
|
286,620
|
|
Other non-current liabilities
|
688,542
|
|
|
630,345
|
|
Total liabilities
|
841,181
|
|
|
974,127
|
|
|
|
|
|
Stockholders' equity
|
|
|
|
Common stock
|
1,179
|
|
|
830
|
|
Other stockholders' equity
|
283,631
|
|
|
283,522
|
|
Accumulated other comprehensive income (loss)
|
(51,285
|
)
|
|
(43,135
|
)
|
Total Stockholders' Equity
|
233,525
|
|
|
241,217
|
|
Total liabilities and equity
|
$
|
1,074,706
|
|
|
$
|
1,215,344
|
|
TETRA Technologies, Inc. and Subsidiaries
Schedule I - Condensed Financial Information of Registrant (Parent Only)
Statements of Operations
(In Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
|
|
|
|
|
|
|
Net sales and gross revenues
|
|
$163,232
|
|
$314,567
|
|
$303,349
|
|
|
|
|
|
|
|
Cost of revenues
|
|
119,350
|
|
|
189,362
|
|
|
210,787
|
|
Depreciation, amortization, and accretion
|
|
49,687
|
|
|
50,708
|
|
|
32,267
|
|
General and administrative expenses
|
|
25,922
|
|
|
69,925
|
|
|
58,978
|
|
Interest expense
|
|
22,550
|
|
|
19,901
|
|
|
19,983
|
|
Other income (expense), net
|
|
4,247
|
|
|
1,097
|
|
|
2,934
|
|
Equity in net loss of subsidiaries
|
|
181,780
|
|
|
192,242
|
|
|
141,203
|
|
|
|
403,536
|
|
|
523,235
|
|
|
466,152
|
|
Income (loss) before taxes and discontinued operations
|
|
(240,304
|
)
|
|
(208,668
|
)
|
|
(162,803
|
)
|
Provision (benefit) for income taxes
|
|
(911
|
)
|
|
799
|
|
|
4,772
|
|
Income (loss)
|
|
$
|
(239,393
|
)
|
|
$
|
(209,467
|
)
|
|
$
|
(167,575
|
)
|
TETRA Technologies, Inc. and Subsidiaries
Schedule I - Condensed Financial Information of Registrant (Parent Only)
Statements of Cash Flows
(In Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2016
|
|
2015
|
|
2014
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
14,861
|
|
|
$
|
100,932
|
|
|
$
|
87,451
|
|
|
|
|
|
|
|
|
Investing activities:
|
|
|
|
|
|
|
Acquisition of businesses, net of cash acquired
|
|
—
|
|
|
—
|
|
|
(14,799
|
)
|
Purchases of property, plant and equipment
|
|
(2,931
|
)
|
|
678
|
|
|
(26,067
|
)
|
Proceeds from sale of property, plant, and equipment
|
|
1,325
|
|
|
2,146
|
|
|
6,210
|
|
Advances and other investing activities
|
|
314
|
|
|
1,626
|
|
|
616
|
|
Other investing activities
|
|
(10,000
|
)
|
|
—
|
|
|
—
|
|
Net cash provided by (used in) investing activities
|
|
(11,292
|
)
|
|
4,450
|
|
|
(34,040
|
)
|
Financing activities:
|
|
|
|
|
|
|
Proceeds from long-term debt
|
|
349,550
|
|
|
472,896
|
|
|
143,188
|
|
Payments of long-term debt
|
|
(516,900
|
)
|
|
(575,070
|
)
|
|
(195,956
|
)
|
Distributions
|
|
—
|
|
|
—
|
|
|
—
|
|
Finance costs
|
|
(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
|
|
|
1,032
|
|
Net cash used in financing activities
|
|
(3,569
|
)
|
|
(105,613
|
)
|
|
(51,736
|
)
|
Increase (decrease) in cash
|
|
—
|
|
|
(231
|
)
|
|
1,675
|
|
Cash and cash equivalents at beginning of period
|
|
—
|
|
|
231
|
|
|
(1,444
|
)
|
Cash and cash equivalents at end of period
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
231
|
|
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.