UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON D.C. 20549

 

 

FORM 10-K

(MARK ONE)

[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2012

OR

[   ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM             TO             .     

 

COMMISSION FILE NUMBER 1-13455

 

TETRA Technologies, Inc.

(EXACT NAME OF THE REGISTRANT AS SPECIFIED IN ITS CHARTER)

 

DELAWARE

74-2148293

(STATE OR OTHER JURISDICTION OF

(I.R.S. EMPLOYER

INCORPORATION OR ORGANIZATION)

IDENTIFICATION NO.)

 

 

24955 INTERSTATE 45 NORTH

 

THE WOODLANDS, TEXAS

77380

(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)

(ZIP CODE)

 

 

REGISTRANT’S TELEPHONE NUMBER, INCLUDING AREA CODE: (281) 367-1983

 

 

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

 

 

COMMON STOCK, PAR VALUE $.01 PER SHARE

NEW YORK STOCK EXCHANGE

(TITLE OF CLASS)

(NAME OF EXCHANGE ON WHICH REGISTERED)

 

 

RIGHTS TO PURCHASE SERIES ONE

 

JUNIOR PARTICIPATING PREFERRED STOCK

NEW YORK STOCK EXCHANGE

(TITLE OF CLASS)

(NAME OF EXCHANGE ON WHICH REGISTERED)

 

 

S ECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE

INDICATE BY CHECK MARK IF THE REGISTRANT IS A WELL-KNOWN SEASONED ISSUER (AS DEFINED IN R ULE 405 OF THE SECURITIES ACT).
YES [ X ]   NO [   ]

INDICATE BY CHECK MARK IF THE REGISTRANT IS NOT REQUIRED TO FILE REPORTS PURSUANT TO SECTION 13 OR SECTION 15 (d) OF THE ACT. YES [   ]   NO [ X ]

INDICATE BY CHECK MARK WHETHER THE REGISTRANT (1) HAS FILED ALL REPORTS REQUIRED TO BE FILED BY SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE REGISTRANT WAS REQUIRED TO FILE SUCH REPORTS) AND (2) HAS BEEN SUBJECT TO SUCH FILING REQUIREMENTS FOR THE PAST 90 DAYS. YES [ X ]   NO [   ]

INDICATE BY CHECK MARK WHETHER THE REGISTRANT HAS SUBMITTED ELECTRONICALLY AND POSTED ON ITS CORPORATE WEB SITE, IF ANY, EVERY INTERACTIVE DATA FILE REQUIRED TO BE SUBMITTED AND POSTED PURSUANT TO RULE 405 OF REGULATION S-T DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE REGISTRANT WAS REQUIRED TO SUBMIT AND POST SUCH FILES).
YES  [ X ]  NO [   ]

INDICATE BY CHECK MARK IF DISCLOSURE OF DELINQUENT FILERS PURSUANT TO ITEM 405 OF REGULATION S-K IS NOT CONTAINED HEREIN, AND WILL NOT BE CONTAINED, TO THE BEST OF REGISTRANT’S KNOWLEDGE, IN DEFINITIVE PROXY OR INFORMATION STATEMENTS INCORPORATED BY REFERENCE IN PART III OF THIS FORM 10-K OR ANY AMENDMENT TO THIS FORM 10-K. [ X ]

INDICATE BY CHECK MARK WHETHER THE REGISTRANT IS A LARGE ACCELERATED FILER, AN ACCELERATED FILER , A NON-ACCELERATED FILER , OR A SMALLER REPORTING COMPANY. SEE THE DEFINITION S OF “ LARGE ACCELERATED FILER ,” ACCELERATED FILER , AND “SMALLER REPORTING COMPANY”   IN RULE  12b-2 OF THE EXCHANGE ACT . (CHECK ONE):

LARGE ACCELERATED FILER [ X ]

ACCELERATED FILER [ ]

NON-ACCELERATE D FILER [   ]

SMALLER REPORTING COMPANY [   ]

INDICATE BY CHECK MARK WHETHER THE REGISTRANT IS A SHELL COMPANY (AS DEFINED IN RULE 12b-2 OF THE EXCHANGE ACT).
YES [   ]  NO [ X ]

THE AGGREGATE MARKET VALUE OF COMMON STOCK HELD BY NON-AFFILIATES OF THE REGISTRANT WAS $538,036,074 AS OF JUNE 30, 2012, THE LAST BUSINESS DAY OF THE REGISTRANT’S MOST RECENTLY COMPLETED SECOND FISCAL QUARTER.

N UMBER OF SHARES OUTSTANDING OF THE ISSUER’S COMMON STOCK AS OF FEBRUARY 26, 2013 WAS 78,200,008 SHARES.

DOCUMENTS INCORPORATED BY REFERENCE

P ART III INFORMATION IS INCORPORATED BY REFERENCE TO THE REGISTRANT’S PROXY STATEMENT FOR ITS ANNUAL MEETING OF STOCKHOLDERS TO BE HELD MAY 3, 2013 TO BE FILED WITH THE SECURITIES AND EXCHANGE COMMISSION WITHIN 120 DAYS OF THE END OF THE REGISTRANT’S FISCAL YEAR.

 


TABLE OF CONTENTS

 

 

 

Part I

 

Item 1.

Business

1

Item 1A.

Risk Factors

12

Item 1B.

Unresolved Staff Comments

23

Item 2.

Properties

23

Item 3.

Legal Proceedings

26

Item 4.

Mine Safety Disclosures

26

 

 

 

 

Part II

 

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters, and

 

 

     Issuer Purchases of Equity Securities

26

Item 6.

Selected Financial Data

28

Item 7.

Management’s Discussion and Analysis of Financial Condition

 

 

     and Results of Operation

34

Item 7A.

Quantitative and Qualitative Disclosures about Market Risk

53

Item 8.

Financial Statements and Supplementary Data

54

Item 9.

Changes in and Disagreements with Accountants on Accounting

 

 

     and Financial Disclosure

54

Item 9A.

Controls and Procedures

54

Item 9B.

Other Information

55

 

 

 

 

Part III

 

Item 10.

Directors, Executive Officers, and Corporate Governance

55

Item 11.

Executive Compensation

55

Item 12.

Security Ownership of Certain Beneficial Owners and Management and

 

 

     Related Stockholder Matters

55

Item 13.

Certain Relationships and Related Transactions, and Director Independence

55

Item 14.

Principal Accounting Fees and Services

55

 

 

 

 

Part IV

 

Item 15.

Exhibits, Financial Statement Schedules

56

 

 


This Annual Report on Form 10-K contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, including, without limitation, statements concerning future sales, earnings, costs, expenses, acquisitions or corporate combinations, asset recoveries, worki ng capital, capital expenditures, financial condition, and other results of operations. Such statements reflect our current views with respect to future events and financial performance and are subject to certain risks, uncertainties and assumptions, including those discussed in “Item 1A. Risk Factors.”  Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those anticipated, believed, estimated, or projected. Unless the context requires otherwise, when we refer to “we,” “us,” and “our,” we are describing TETRA Technologies, Inc. and its subsidiaries on a consolidated basis.

 

PART I

 

Item 1. Business.

 

General

 

We are a geographically diversified oil and gas services company, focused on completion fluids and associated products and services, frac water management, after-frac flow back, production well testing, offshore rig cooling, compression based production enhancement, 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 three divisions – Fluids, Production Enhancement, 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 comprehensive frac water management services.

 

Our Production Enhancement Division consists of two operating segments: Production Testing and Compressco. The Production Testing segment provides after-frac flow back, 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 certain oil and gas basins in certain regions in South America, Africa, Europe, the Middle East, and Australia.

 

The Compressco segment provides compression-based production enhancement services, which are used in both conventional wellhead compression applications and unconventional compression applications , and in certain circumstances , well monitoring and sand separation services. Compressco provides these services throughout many of the onshore oil and gas producing regions of the United States, as w ell as certain basins in Mexico and Canada, and certain countries in South America, Eastern Europe, and the Asia -Pacific region.

 

Our Offshore Division consists of two operating segments: Offshore Services and Maritech. The Offshore Services segment provides (1) downhole and subsea oil and gas well plugging and abandonment 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 saturated air 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 current operations primarily consist of the ongoing abandonment and decommissioning associated with its remaining operated and non-operated offshore wells, facilities, and production platforms. Maritech intends to acquire a significant portion of these services for its operated properties from the Offshore Division’s Offshore Services segment.

 

We continue to pursue a growth strategy that includes expanding our existing businesses , with the exception of Maritech, 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.


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We were incorporated in Delaware 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. We make available on our website, free of charge, our Corporate Governance Guidelines, Code of Business Conduct and Ethics, Code of Ethics for Senior Financial Officers, Audit Committee Charter, Management and Compensation Committee Charter, and Nominating and Corporate Governance Committee Charter, as well as our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports as soon as is reasonably practicable after such materials are electronically filed with, or furnished to, the Securities and Exchange Commission (SEC). The information on 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. Information filed with the SEC may be read or copied at the SEC’s Public Reference Room at 100 F Street, N.E., Washington D.C. 20549. Information on operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet website (http://www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers that file electronically. We will also make these documents available in print, free of charge, to any stockholder who requests such information from the Corporate Secretary.

 

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. Although they are used in many types of wells, demand for CBFs is greater in offshore well operations . Our Fluids Division sells CBFs and CBF additives to U.S. and foreign oil and gas exploration and production companies and distributes them to other companies that service customers in the oil and gas industry.

 

Our Fluids Division provides both basic and custom-blended CBFs based on our customers’ specific needs and the proposed application. We also provide a broad range of associated services, including onsite fluid s filtration, handling, and recycling; wellbore cleanup; fluid engineering consultation; and fluid management services ; as well as high - volume water management services for fracturing operations. We offer to repurchase (buyback) from customers used CBFs, 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 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 the CBFs can be reused. Filtration also enables recovery of a greater percentage of used CBFs for reconditioning.

 

The Fluids Division provides domestic onshore oil and gas operators with comprehensive frac water management services, including selection, analysis, treatment, storage, transfer, recycling, and environmental risk mitigation. These services are provided using the Division’s BioRid ® and other above-ground frac water treatment technologies, some of which are patented, and its TETRA ® STEEL 1200 expandable water transfer pipeline system. The Division’s frac water management personnel seek to design environmentally friendly solutions for the unique needs of each customer’s wellsite in order to maximize operational performance and efficiency.

 

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 the water treatment, industrial, cement, food processing, road maintenance , ice melt, agricultural, and consumer products markets. Liquid sodium bromide is also sold into the industrial water treatment markets, where it is used as a biocide in recirculated cooling tower waters and in other applications.


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Our liquid and dry calcium chloride production facilities are located in the United States and Europe. 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 manufacturing 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 plants located in San Bernardino County, California, that produce liquid calcium chloride from underground brine reserves. All of our calcium chloride production facilities have a combined production capacity of more than 1.5 million liquid equivalent tons per year.


We manufacture calcium bromide, zinc bromide, zinc calcium bromide, and sodium bromide at our West Memphis, Arkansas, production facility. A patented and proprietary production 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 this Division.

 

Production Enhancement Division

 

Production Testing Segment. The Production Testing segment of the Production Enhancement Division provides after-frac flow back, production well testing, offshore rig cooling, and other associated services. The segment provides well flow management and evaluation services and data that enables operators to quantify reserves, optimize production , and minimize oil and gas reservoir damage. In addition to after-frac flow back and production well testing , the Production Testing segment provides well control, well cleanup, and laboratory analysis services. The Production Testing segment also provides early-life production solutions designed for newly producing oil and gas wells and provides late-life production enhancement solutions designed to boost and extend the productive life of oil and gas wells. Many of these services involve sophisticated evaluation techniques for reservoir management, including unconventional shale reservoir exploitation and optimization of well workover programs.

 

The Production Testing segment 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. O n April 23, 2012, we acquired the assets and operations of Eastern Reservoir Services (ERS), a division of Patterson-UTI Energy, Inc. , for a cash purchase price of $42.5 million. ERS was a provider of production testing and after-frac flow back services to oil and gas operators in the Appalachian and U.S. Rocky Mountain regions. On July 31, 2012, we acquired the assets and operations of Greywolf Production Systems Inc. and GPS Ltd. (together, Greywolf) for a cash purchase price of approximately $55.5 million. Greywolf was a provider of production testing and after-frac flow back services to oil and gas operators in western Canada , the U.S. Williston Basin (including the Bakken formation) , and the Niobrara Shale formation of the U.S. Rocky Mountain region. These acquisition s represent a strategic geographic expansion of our existing Production Testing segment operations into additional oil and gas producing regions in the U.S and Canada . The Production Testing segment has domestic operating locations in Colorado, Louisiana, North Dakota, Oklahoma, Pennsylvania, and throughout Texas. Internationally, the segment has locations in Mexico and Canada , South America, Europe, North Africa, the Middle East , and Asia .

 

On March 9, 2012, we acquired 100% of the outstanding common stock of Optima So lutions Holdings Limited (OPTIMA ), 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. The acquisition of OPTIMA , which is based in Aberdeen, Scotland, enables our Production Testing segment to provide its customers with a broader range of production testing related services and expands the segment’s presence in many significant global markets. Including the impact of additional working capital received and other adjustments to the purchase price, we paid 41.2 million pounds sterling (approximately $65.0 million equivalent at the time of closing ) in cash as t he purchase price for the OPTIMA stock at closing , and we may pay up to an additional 4 million pounds sterling in contingent purchase price consideration, depending on a define d measure of earnings for OPTIMA over the two years subsequent to the closing.


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The Production Testing segment also operates under a technical management contract to perform engineering, procurement, and installation of equipment needed for the cleanup and removal of oil bearing materials at two refinery locations in South America. The remaining services to be provided under this contract are expected to continue to be performed in stages over the next twelve month period .


Compressco Segment. The Division’s Compressco segment provides compression-based production enhancement services, which are used in both conventional wellhead compression applications and unconventional compression applications to a broad base of natural gas and oil exploration and production companies. Over time, oil and natural gas wells exhibit declining pressure and production.   Production enhancement technologies are designed to enhance daily production and total recoverable reserves . C ompression-based production enhancement services are utilized to increase reserves production by deliquifying wells, lowering wellhead pressure, and increasing gas velocity. The Compressco segment’s conventional applications include production enhancement services for dry gas wells , liquid loaded gas wells, and backside auto injection system applications . Its unco nventional applications are utilized primarily in connection with oil and l iquids production , and include vapor recovery and casing gas system applications . In Mexico, i n certain circumstances, the segment also provides ongoing well monitoring services and automated sand separation services in connection with its primary production enhancement services. Although Compressco’s compression-based services are applied primarily to mature wells with low formation pressures, they are also utilized effectively on newer wells that have experienced significant production declines.

 

Virtually all of our Compressco segment’s operations are conducted through our subsidiary, Compressco Partners, L.P. (Compressco Partners), a Delaware limited partnership. We own approximately 83% of the outstanding ownership interest of Compressco Partners.

 

Compressco’s field services are performed by its highly trained staffs of regional service supervisors, optimization specialists, and field mechanics. Compressco designs and manufactures most of the compressors it uses to provide production enhancement services, and in certain markets , sells compressor units to customers. Compressco’s fleet of compressor units totaled 3,743 as of December 31, 2012, of which 3,198 units were in service .

 

Compressco primarily utilizes its natural gas powered GasJack ® and electric VJack TM compressor units to provide its compression services. Compressco utilizes its GasJack ® and VJack TM   units to provide compression services to its customers, primarily on a month-to-month basis. Compressco services its compressors and provides maintenance services on sold units through a staff of mobile field technicians who are based throughout Compressco’s market areas. The GasJack ® unit increases gas production by reducing surface pressure to allow wellbore liquids that can hinder gas flow to be carried to the surface. The liquids are separated from the gas and liquid-free gas flows into the GasJack ® unit, where the gas is compressed. That gas is then cooled before being sent to the gas sales line. The separated fluids are either stored in an onsite customer-provided tank or injected into the gas sales line for separation downstream. The 46-horsepower GasJack ® unit is an integrated power/compressor unit equipped with an industrial 460-cubic inch, V-8 engine that uses natural gas from the well to power one bank of cylinders that, in turn, powers the other bank of cylinders, which provide compression. Compressco utilizes its 40-horsepower electric VJack TM compressor unit to provide production enhancement services on wells located in larger, mature oil fields and in environmentally sensitive areas where electric power is available at the production site. The VJack TM unit provides production uplift with zero engine-driven emissions, and Compressco believes it requires significantly less maintenance than a natural gas powered compressor. The VJack TM unit is primarily designed for vapor recovery applications (to capture natural gas vapors emitting from closed storage tanks after production and to reduce storage tank pressures) and casing gas systems applications on oil wells.

 

See “Note Q – Industry Segments and Geographic Information” in the Notes to Consolidated Financial Statements for financial information about this Division.

 

Offshore Division

 

Offshore Services Segment. The Offshore Services segment provides (1) downhole and subsea services such as wel l 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 saturated air 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.


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In providing services, our Offshore Services segment utilizes rigless P&A packages, two heavy lift vessels, several dive support vessels and other dive support assets. 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 saturated air diving services to its customers through our subsidiary, Epic Diving & Marine Services (Epic). Well abandonment, decommissioning, and certain construction services are performed primarily offshore in the U.S. Gulf of Mexico. The Offshore Services segment provides offshore cutting services and tool rentals through its E.O.T. Cutting (EOT) operations. 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 toppled or severely damaged by windstorms . In December 2012, the Offshore Services segment sold its electric wireline operation. The Offshore Services segment provides services to major oil and gas companies and independent operators, including Maritech, through its facilities located in Lafayette, Broussard, Belle Chasse, and Houma, Louisiana.

 

O ur Offshore Services segment’s fleet of service vessels has expanded and contracted in size in recent years in response to changing demand s for its services. Including the 1,600-metric-ton heavy lift derrick barge we purchased in July 2011, we currently have three vessels capable of performing heavy lift decommissioning and construction projects and integrated operations on oil and gas production platforms. One of the heavy lift vessels, however, has recently been idled due to decreased demand in the shallow waters of the Gulf of Mexico in which it has operated historically. The Offshore Services segment is pursuing the sale of this vessel. T he Offshore Services segment leases additional dive support vessels as they are needed. One of these leased vessels, the Adams Challenge , as well as one of the Offshore Services segment’s owned dive support vessels, the Epic Explorer, include saturation diving system s that are rated for up to 1,000 - foot dive depths.

 

Among other factors, demand for our Offshore Service segment’s operations in the Gulf of Mexico is affected by federal regulations governing the abandonment and decommissioning of offshore wells , production platforms and pipelines, particularly following the April 2010 Macondo well oil spill. Regulations issued by the Bureau of Ocean Energy, Management, Regulation, and Enforcement (BOEMRE) include Notice To Lessees 2010-G05: “Decommissioning Guidance for Wells and Platforms” (NTL 2010-G05, known as the “Idle Iron Guidance”), which requires that permanent plugs be set in nearly 3,500 nonproducing wells in the U.S. Gulf of Mexico and that approximately 650 oil and gas production platforms in the U.S. Gulf of Mexico be dismantled if they are no longer being used. In October 2011, the BOEMRE’s responsibilities were divided between the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement ( BSEE ) , which now issues offshore permits, regulates offshore contractors, and oversee s 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 provide s 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 an 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. In addition, Maritech is seeking to sell its remaining interests in oil and gas producing properties.

 

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 remaining well abandonment and decommissioning of its offshore oil and gas platforms and facilities. During the three year period ended December 31, 2012, Maritech has expended approximately $ 292.2 ­ million on such efforts. Approximately $ 87.4 million of Maritech decommissioning liabilities remain as of December 31, 2012, and approximately $ 80.7 million of this amount is planned to be performed during 2013.

 

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. 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


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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 this 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 Division also recycles used calcium and zinc bromide CBFs repurchased from its oil and gas customers.

 

The Division produces liquid calcium chloride, either from underground brine reserves or by reacting hydrochloric acid with limestone. The 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 brine (tail brine) obtained from Chemtura Corporation (Chemtura) that contains calcium chloride . We also produce calcium chloride at our two plants in San Bernardino County, California, by solar evaporation of underground brine reserves that contain calcium chloride. These underground brine reserves are deemed adequate to supply our foreseeable need for calcium chloride at those plants.

 

The Division’s primary sources of hydrochloric acid are chemical 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. We obtain hydrochloric acid and limestone raw materials for our Lake Charles, Louisiana, facility from a variety of sources to produce liquid calcium chloride. In February 2011, we shut down the dry ( pellet ) operation at the Lake Charles, Louisiana plant.

 

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 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 Division’s El Dorado , Arkansas, calcium chloride plant with raw material tail brine from its Arkansas bromine 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 holds certain rights to participate in future development of the Magnolia, Arkansas, assets.

 

The Production Testing segment of our Production Enhancement Division purchases its production testing and rig cooling equipment and components from third-party manufacturers. The Compressco segment designs and assembles the compressor units it uses to provide wellhead compression-based production enhancement services and the majority of the required components are obtained from third party suppliers. Compressco acquires its well monitoring and sand separation equipment and components from third party manufacturers or from the Production Testing segment. Some of the components used in the assembly of compressor units , 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 would not be severe.


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Market Overview and Competition

 

Fluids Division

 

Our Fluids Division provides its products and services to oil and gas exploration and production companies  in the United States and certain international markets. 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. The Division also markets to customers with deepwate r operations that utilize high volumes of CBFs and can be subject to harsh downhole conditions , such as high pressure and high temperatures. Deepwater drilling activity in the U.S. Gulf of Mexico was significantly affected by the April 2010 well blowout of the Macondo well, which resulted in a temporary drilling moratorium in the deepwater Gulf of Mexico as well as a series of regulatory reforms associated with offshore oil and gas operations. Although Gulf of Mexico rig count activity during the last part of 2012 reflects a return of pre-Macondo offshore drilling activity levels , demand for offshore CBF products are generally driven by completion activity, which is also increasing to early 2010 levels. Demand may also continue to be affected by future regulatory restrictions.

 

During the past three years, a portion of the growth of the Division’s U.S. operations ha s been due to increased industry demand for frac water management services in unconventional shale gas and oil reservoirs. The Division provides frac water management services to a wide range of onshore oil and gas operators located in the most significant domestic shale gas and oil reservoirs, including the Marcellus, Utica, Barnett, Eagle Ford, Fayetteville, Cana Woodford, Haynesville, and Granite Wash.

 

The Division’s principal competitors in the sale of CBFs to the oil and gas industry are Baker Hughes , Baroid Corporation 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 Fl uids Division include Anadarko, Devon, Dynamic Offshore Resources, Halliburton, Marathon Oil, Petrobras (the national oil company of Brazil), Shell Oil, and Tullow Oil. The Division also sells its CBF products through various distributors. Competitors for the Division’s frac 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. The 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 the industrial water treatment markets as a biocide under the BioRid ® tradename. Most of these markets are highly competitive. The Division’s European calcium chloride manufacturing 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 Industrial del Alkali in North America, and Brunner Mond, Solvay, and NedMag in Europe.

 

Production Enhancement Division

 

Production Testing Segment. 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 segment provides the specialized equipment and qualified personnel to address these impediments to production. The Production Testing segment also provides certain services designed to accommodate the unique after-frac flow back and testing demands of shale gas reservoirs. In addition, following the March 2012 acquisition of OPTIMA , the Production Testing segment offers offshore oil and gas rig cooling services and associated products that suppress heat generated by high-rate flaring of hydrocarbons during offshore well test operations. During the past two years, the Production Testing segment has expanded its after-frac flowback and production testing equipment fleet and acquired operations to serve the rapidly growing demand for these se rvices. The Production Testing s egment ’s offshore rig cooling operations, obtained t hrough the acquisition of OPTIMA , primari ly serve mark ets in the North Sea, Australia and Asia-Pacific, the Middle East, and South America. As a result of the acquisitions of ERS and Greywolf, the Production Testing segment has expanded its operations to serve the Appalachian, U.S. Rocky Mountain , and western Canada markets. In addition, the Production Testing segment continues to serve the continuing demand for services associated with many of the domestic shale gas reservoirs, including the Marcellus, Barnett, Eagle Ford, Fayetteville, Cana Woodford, Haynesville, Bakken, and Niobrara .


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The U.S. and Canadian production testing market s are highly competitive , and competition is based on availability of equipment and qualified personnel, as well as price, quality of service, and safety record. We believe that our equipment, skilled personnel, operating procedures, and safety record give us a competitive advantage in the marketplace. The Production Testing segment plans to continue growing its international operations in order to serve most major oil and gas markets worldwide, both organically and through additional strategic acquisitions. Competition in onshore U.S. production testing markets is primarily dominated by numerous small, privately owned operators. Expro International , Halliburton, Schlumberger, and Weatherford, are major competitors in the international markets we serve. The major customers for this segment include BHP Billiton, Cabot, Chesapeake, ConocoPhillips, Encana, Geosouthern, Halliburton, Shell Oil, PEMEX (the national oil company of Mexico), Petrobras, Saudi ARAMCO (the national oil company of Saudi Arabia), and other national oil companies in foreign countries.

 

Compressco Segment. The Division’s Compressco segment provides its services to a broad base of na t ural gas and oil exploration and production companies operating throughout many of the onshore producing regions of the United States. Compressco also has significant operations in Mexico and Canada , and a growing presence in certain countries in South America, Eastern Europe, and the Asia-Pacific region. While most of Compressco’s domestic services are performed in the San Juan Basin, Permian Basin , and Mid-Continent region of the United States, it also has a substantial presence in other U.S. producing regions, including the Ark-La-Tex region, North Texas, South Texas, the Central and North ern Rockies, and California . Compressco has historically fo cused on serving customers with production in mature conventiona l fields, but it now also services customers in some of the largest and fastest growing unconventional shale gas resource reservoirs in the United States, including the Co tton Valley Trend, Barnett, Fayetteville , Cana Woodford, Piceance, Bakken, Eagle Ford, and Marcellus . Compressco continues to seek opportunities to further expand its operations into other regions in the Western Hemisphere and elsewhere in the world.

 

The wellhead compression-based production enhancement services business is highly competitive, and competition primarily comes from companies that utilize packages consisting of a screw compressor with a separate engine driver or a reciprocating compressor with a separate engine driver. To a lesser extent, Compressco faces competition from large companies that have traditionally focused on higher-horsepower natural gas gathering and transportation equipment and services. Compressco’s strategy is to compete on the basis of superior services at a competitive price. Compressco believes that it is competitive because of the significant increases in the value of natural gas wells that result from the use of its services, it s superior customer service, its highly trained field personnel, and the quality of the compressor units it uses to provide the services. Compressco’s major customers include PEMEX, BP, Anadarko, Devon Energy, and Apache .

 

Offshore Division

 

Offshore Services Segment. D emand drivers for the Offshore Services segment’s offshore well abandonment and decommissioning services include the maturity and decline of producing fields in the Gulf of Mexico, aging offshore platform infrastructure, damage to platforms and pipelines from wind storms, and government regulations. Demand for the Offshore Services segment’s construction and other services is driven by the general level of activity of its customers, which is driven by oil and natural gas prices and government regulation . We believe that the regu lations issued by the BOEMRE, including NTL 2010-G05, the Idle Iron Guidance , may accelerate the pace at which offshore Gulf of Mexico abandonment and decommissioning will be done in the future. The maturity and production decline of Gulf of Mexico oil and gas fields continues to cause an increase in the number of wells to be plugged and abandoned , and platforms and pipelines to be decommissioned.

 

Offshore Gulf of Mexico abandonment and decommissioning activity declined in 2012 compared to the high er activity during the past several years after the 2005 and 2008 hurricane s in the Gulf of Mexico, which destroyed or caused significant damage to a large number of offshore platforms and associated wells. While the vast majority of this hurricane-related recovery and removal activity has been completed , it provided the Offshore Services segment the opportunity to develop and acquire specialized equipment and engineering expertise that may be used to provide such services to customers whose offshore wells and production platforms may be damaged by future storms .

 

Offshore activities in the Gulf of Mexico are highly 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: an adequate fleet of the proper equipment; qualified, experienced personnel; technical expertise to address varying downhole, surface, and subsea conditions, particularly those


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related to damaged wells and platforms; and a comprehensive health, safety and environmental program. In July 2011, our Offshore Services segment purchased a heavy lift derrick barge (the TETRA Hedron) with a 1,600-metric-ton lift capacity, fully revolving crane. The vessel was purchased from Wison (Nantong) Heavy Industry Co., Ltd. and Nantong MLC Tongbao Shipbuilding Co., Ltd. for $62.8 million, subject to certain adjustments. We believe our integrated service package and vessel and equipment fleet s satisfy current market requirements in the U.S. Gulf of Mexico , and allow us to successfully compete.

 

The Offshore Services segment markets its services primarily to major oil and gas companies and independent operators . The Offshore Services segment’s most significant customer during the past three years has bee n Maritech , and the majority of the remaining work to be performed for Maritech on properties it operates is planned to be performed by the Offshore Services s egment during 2013 . Other major customers include Apache, Chevron, McMoRan Exploration, Nexen Petroleum USA Inc., Stone Energy, Versabar, and W&T Offshore. The Offshore Services segment’s services are performed primarily in the U.S. Gulf of Mexico, however, the segment is also seeking to expand its operations to international markets. Our principal competitors in the U.S. Gulf of Mexico market are Cal Dive International, Inc., Offshore Specialty Fabricators, Inc , Superior Energy Services, Inc., and Technip USA (formerly Global Industries, Ltd ) . This market is highly competitive, and competition is based primarily on service, equipment availability, safety record , and price. Our ability to lease or otherwise acquire suitable service vessels and other operating equipment is particularly important to our ability to expand our operations to other markets.

 

Other Business Matters

 

Marketing and Distribution

 

The Fluids Division markets its CBF products through its distribution facilities located in the U.S. Gulf Coast region, the North Sea region of Europe, and certain other foreign markets, including Brazil, West Africa, and the Middle East.

 

Non-oilfield calcium chloride products are also marketed through the Division’s sales offices in California, Missouri, Pennsylvania, and Texas, as well as through a network of distributors in the United States and northern and central Europe. In addition to production facilities in the United States and Europe, the Division has distribution facilities strategically located to provide efficient product distribution.

 

No single customer provided 10% or more of our total consolidated revenues during the year ended December 31, 2012.

 

Backlog

 

Our backlog is not indicative of our estimated future revenues, because a majority of our products and services either are not sold under long-term contracts or do not require long lead times to procure or deliver. Our backlog consists of estimated future revenues associated with a portion of our well abandonment and decommissioning business consisting of the non-Maritech share of the well abandonment and decommissioning work associated with the remaining oil and gas properties operated by Maritech. O ur estimated backlog on December 31, 2012, was $ 3.4 million. This compare s to an estimated backlog of $11.6 million at December 31, 2011.

 

Employees

 

As of December 31, 2012 , we had 3,648 employees. None of our U.S. employees are presently covered by a collective bargaining agreement other than the employees of our Lake Charles, Louisiana, calcium chloride production facility, who are represented by the United Steelworkers Union. Our foreign employees are generally members of labor unions and associations in the countries in which we operate. We believe that our relations with our employees are good.

 

Patents, Proprietary Technology, and Trademarks

 

As of December 31, 2012 , we owned or licensed twenty-five issued U.S. patents and had eleven patent applications pending in the United States. Internationally, we had thirty-two owned or licensed foreign patents and thirty - eight foreign patent applications pending. The foreign patents and patent applications are primarily foreign counterparts to U.S. patents or patent applications. The issued patents expi re at various times through 2030 . We


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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 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 stormwater 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 (OSHA), and other state and local agencies and authorities. Specific environmental laws and regulations applicable to our operations include the Federal Water Pollution Control Act of 1972; the Resource Conservation and Recovery Act of 1976 (RCRA); the Clean Air Act of 1977; the Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA); the Superfund Amendments and Reauthorization Act of 1986 (SARA); the Federal Insecticide, Fungicide, and Rodenticide Act of 1947 (FIFRA); the Toxic Substances Control Act of 1976 (TSCA); the Hazardous Materials Transportation Act of 1975; and the Pollution Prevention Act of 1990. Our operations outside the United States are subject to various foreign governmental laws and regulation s relating to the environment, health and safety, and other regulated activities in the countries in which we operate.

 

We believe that our manufacturing plants and other operations are in substantial compliance with all applicable U.S. and foreign health, safety, and environmental laws and regulations. Since our inception, we have not had a history of any significant fines or claims in connection with environmental or health and safety matters. 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 plant and service 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.

 

The EPA has determined that greenhouse gases present an endangerment to public health and the environment because, according to the EPA, 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, with reporting beginning in 2012 for emissions occurring in 2011. 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.


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Offshore Operations

 

During 2010, BOEMRE issued several Notices to Lessees (NTLs) and other safety regulations implementing additional safety and certification requirements applicable to drilling activities in the Gulf of Mexico, that have resulted in operations and projects being delayed or suspended. These NTLs and regulations include requirements by operators to:

         s ubmit well blowout prevention measures and contingency plans, including demonstrating access to subsea blowout containment resources;

         a bide by new permitting standards requiring detailed, independently certified descriptions of well design, casing, and cementing;

         f ollow new performance-based standards for offshore drilling and production operations; and

         c ertify that the operator ha s complied with all regulations.

 

In October 2011, the BOEMRE’s responsibilities were divided between BOEM and the BSEE, which oversee s the provis ions of the “Idle Iron Guidance . These agencies’ scopes of responsibility include maintaining an invest igation and review unit, providing for public forums and conducting comprehensive environmental analyse s, 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 certain costs in the event of 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 general liability and protection and indemnity policies that provide third-party liability coverage, up to applicable policy limits, for risks of an accidental nature, including but not limited to death and personal injury, collision, damage to fixed and floating objects, pollution, and wreck removal. We also maintain a vessel pollution liability policy that provides coverage for oil or hazardous substance pollution emanating from a vessel, addressing both OPA (Oil Pollution Act of 1990) and CERCLA obligations. This policy also provides coverage for cost of defense, fines, and penalties. The Maritech energy insurance package provides operational all risks coverage (excluding named windstorm coverage) for physical loss or damage to scheduled offshore property, including removal of wreck and/or debris, and for operator’s extra expense such as control of well, redrill/extra expense, and pollution and cleanup.

 

Apart from our Maritech operations, 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:

 

(1) 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.

 

(2) 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.

 

(3) 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 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 B SEE and has designated employees 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.

 

Forward Looking Statements

 

Some information included in this report, other materials filed or to be filed with the SEC, as well as information included in oral statements or other written statements made or to be made by us contain or incorporate by reference certain statements (other than statements of historical fact) that constitute forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. When used herein, the words “assume,” “may,” “will,” “should,” “goal,” “anticipate,” “expect,” “estimate,” “could,” “believes,” “seeks,” “plans,” “intends,” “projects” or “targets” and similar expressions that convey the uncertainty of future events or outcomes are intended to identify forward-looking statements.

 

Where any forward-looking statement includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that, while we believe these assumptions or bases to be reasonable and to be made in good faith, assumed facts or bases almost always vary from actual results, and the difference between assumed facts or bases and actual results could be material, depending on the circumstances. It is important to note that actual results could differ materially from those projected by such forward-looking statements.

 

Although we believe that the expectations reflected in such forward-looking statements are reasonable and such forward-looking statements are based upon the best data available at the date this report is filed with the SEC, we cannot assure you that such expectations will prove correct. Factors that could cause our results to differ materially from the results discussed in such forward-looking statements include, but are not limited to, the following:

         economic and operating conditions that are outside of our control, including the supply, demand, and prices of crude oil and natural gas;

         the levels of competition we encounter;

         the impact of market conditions and activity levels of our customers;

         the demand for our products and services in the Gulf of Mexico , which could continue to be adversely impacted by increased regulation and continuing regulatory uncertainty;

         budgetary constraints and ongoing violence i n Mexico;

         the availability of raw materials and labor at reasonable prices;

         possible impairments of long-lived assets, including goodwill;

         the potential impact of the loss of one or more key employees;

         risks related to our growth strategies;

         operating and safety risks inherent in our oil and gas services operations;

         production volumes and profitability of our El Dorado, Arkansas , facility;

         cost, availability, and adequacy of insurance and the ability to recover thereunder;

 

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         technological obsolescence;

         risks arising from the use of fixed price contracts;

         the valuation of decommissioning liabilities;

         weather risks, including the risk of physical damage to our platforms, facilities, and equipment;

         the availability of capital (including any financing) to fund our business strategy and/or operations , and our ability to comply with covenants and restrictions resulting from such financing;

         exposure to credit risks from our customers;

         uncertainties about plugging and a bandoning wells and structures, including the wells and structures previously sold;

         foreign currency and interest rate risks;

         Compressco’s ability to generate sufficient cash from operations to make cash distributions;

         the impact of existing and future laws and regulations;

         risks related to our foreign operations;

         environmental risks;

         estimates of hurricane repair costs;

         acquisition valuation and integration risks; and

         loss or infringement of o ur intellectual property rights.

 

All such forward-looking statements in this document are expressly qualified in their entirety by the cautionary statements in this paragraph, and we undertake no obligation to publicly update or revise any forward-looking statements.

 

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 products and services is materially dependent on the supply, demand, and prices for oil, natural gas, and competing energy sources, and is more specifically dependent on the supply, demand, and prices for the products and services we offer, both in the United States and in the foreign countries in which we operate. These factors are also influenced by the U.S., foreign, and regional economic, financial, business, political, and social conditions within the markets we serve. Oil and gas prices and, therefore, the levels of well drilling, completion, workover, and production activities, tend to fluctuate. Worldwide economic and political events, including initiatives by the Organization of Petroleum Exporting Countries and increasing or decreasing demand in other large world economies as well as tremendous growth in natural gas supplies in the U.S. from shale reserves, have contributed to, and are likely to continue to contribute to, price volatility. The expansion of alternative energy supplies that compete with oil and gas, improvements in energy conservation, and improvements in the energy efficiency of vehicles, plants, equipment, and devices will also reduce oil and gas consumption or slow its growth.

 

In particular, U.S. natural gas prices have been negatively affected by overall reduced energy demand in the U.S. due to economic conditions and weather, and the increase in natural gas supplies from shale gas drilling. Low natural gas prices ha ve negatively affected the operating cash flows and exploration and development activities and plans of many of our customers and could have a negative impact on the demand for many of our products and services.

 

If economic conditions or energy prices deteriorate , there may be additional constraints on oil and gas industry spending levels. Reduced spending levels would negatively impact the demand for many of our products and services and the prices we charge for these products and services, which would negatively affect our revenues and future growth.

 

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During times when oil or natural gas prices are low, many of our customers are more likely to experience a downturn in their financial condition. Poor economic conditions may also lead to additional constraints on the operating cash flows of our customers, potentially impacting their ability to pay us in a timely manner, which could result in increased customer bankruptcies and uncollectible receivables.

 

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. To the extent competitors offer comparable produ cts or services at lower prices or higher quality, 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. Such activity could 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 product s and service s 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, developm ent, and acquisition activities and plugging , abandonment , and decommissioning costs on Maritech’s remaining offshore production platforms , wells and pipelines . 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.

 

The demand for our products and services in the Gulf of Mexico could continue to be adversely impacted by increased regulation and continuing regulatory uncertainty.

 

Since the April 20, 2010, blowout on the Macondo well, operations in the U.S. Gulf of Mexico have been affected by an increas ingly stringent regulatory environment. The BOEMRE issued several regulations, including notices to U.S. Gulf of Mexico operators, which are focused on offshore operating requirements, spill cleanup , and enforcement matters. These regulations also implement additional safety and certification requirements applicable to drilling activities in the Gulf of Mexico that have resulted in operations and projects in the past being curtailed or suspended. Although permitting levels and Gulf of Mexico rig count activity during late 2012 indicate that activity levels have returned to pre-Macondo levels, demand for our products and services in the Gulf of Mexico will continue to be affected by future regulatory restrictions . Future regulatory requirements could further 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.

 

The majority of our business in Mexico is performed for Petróleos Mexicanos (PEMEX) , and any cutbacks by the Mexican Government on PEMEX’s annual spending budget or security disruptions in Mexico could adversely affect our business, financial condition, results of operations , and cash flows.

 

The majority of our business in Mexico is performed for PEMEX. For the twelv e months ended December 31, 2012 , PEMEX accounted for approximately 7.6% of our consolidated revenues and a significant amount of operating cash flows. No work or services are guaranteed to be ordered by PEMEX under our contracts with PEMEX, which typically range from six months to two years in length. PEMEX is a decentralized public entity of the Mexican Government, and , therefore , the Mexican Government controls PEMEX, as well as its annual budget, which is approved by the Mexican Congress. The Mexican Government may cut spending in the future. These cuts could adversely affect PEMEX’s annual budget and, thus, its ability to engage us or compensate us for our services. Additionally, at the expiration of our current contracts, we may be required to participate in an open auction to renew them.

 

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During the past several years, incidents of security disruptions throughout many regions of Mexico have increased , including d rug related gang activity. Certain incidents of violence have occurred in regions served by us and have resulted in the interruption of our operations . T hese interruptions could continue or increase in the future. To the extent that such security disruptions continue or increase, our operations will continue to be affected, and the levels of revenue and operating cash flow from our Mexican operations could be reduced .

 

Under the Ley de Petróleos Mexicanos (the “PEMEX Law”), PEMEX has authority to contract through an auction process with third parties for the exploration, development, and production of hydrocarbons. Our existing contracts with PEMEX  have durations of up to two years and, when these contracts with PEMEX expire, we may be required to participate in an open auction to renew them. Any failure by us to renew our existing contracts with PEMEX or renew them on favorable terms could materially adversely affect our business, financial condition, results of operations and cash flows .

 

PEMEX has authority to contract through an auction process with third parties for the exploration, development, and production of hydrocarbons. The PEMEX Law permits three types of contracting: contracts resulting from open auctions or invitation-only auctions with at least three invitees, or direct contracting. To utilize an invitation-only auction or a direct contract, PEMEX must provide written justification as to why the specific circumstances of the proposed service contract require less than an open auction. Additionally, open auctions must conform with one of three selected bidder models: either all bidders must be Mexican entities, all bidders must be Mexican entities or foreign entities whose countries of origin are parties to free trade agreements with Mexico that include sections related to governmental procurement, or bidders may be of any national origin. PEMEX may only select the third option if PEMEX determines that either (i) the Mexican market cannot adequately meet the needs of the contract, (ii) the third option would be better for PEMEX in terms of price or quality, (iii) the second bidder model was attempted but was unsuccessful, or (iv) the contracts are financed by certain legally required types of foreign loans. In addition, under the PEMEX Law, there may be other qualifications that must be met by bidding service providers. Bidders must meet and maintain all required qualifications at the time of bidding and throughout the term of the contract.

 

Our existing contracts with PEMEX have durations up to two years and, when they expire, we may be required to participate in an open auction to renew them. A ny failure by us to renew our existing contracts with PEMEX or renew them on favorable terms could adversely affect our business, financial condition, results of operations, and cash flows.

 

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, including calcium chloride, calcium bromide, zinc bromide, zinc calcium bromide, and sodium bromide, some of which we manufacture and some of which are purchased from third parties. We also sell calcium chloride and sodium bromide to non-energy markets. Sales of calcium chloride and bromide compound 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 bromide compound products, we use underground br omine , hydrobromic acid, and other raw materials which are purchased from third parties. We rely on Chemtura as a supplier of raw materials, both for our bromide compound products as well as for our El Dorado, Arkansas, calcium chloride plant. If we are unable to acquire these raw material s 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 production testing and rig cooling equipment and wellhead compressor units requires the purchase of many types of 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 Production Enhancement Division may be adversely affected due to our dependence on these key suppliers.

 

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Changes in the economic environment could result in significant impairments of certain of our long-lived assets, including goodwill.

 

Changes in the economic environment could result in decreased 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, 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 an impairment charge to earnings, resulting in increased earnings volatility.

 

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 and our market capitalization, future cash flows, and slower growth rates in our industry. If economic and market conditions decline, we may be required to record a charge to earnings during the period in which any impairment of our goodwill is determined, resulting in a negative impact on our results of operations.

 

Our success depends upon the continued contributions of our personnel, many of whom would be difficult to replace, and the continued ability to attract new employees.

 

Our success depends on our ability to attract, train, and retain skilled management and employees at reasonable compensation levels. The delivery of our products and services requires personnel with specialized skills and experience. In addition, our ability to expand our operations depends in part on our ability to increase the size of our skilled labor force. The demand for skilled managers and workers in the U.S. Gulf Coast region and other regions in which we operate is high, and the supply is limited. A lack of qualified personnel, therefore, could adversely affect operating results.

 

Operating, Technological, and Strategic Risks

 

We face risks related to our growth strategy.

 

Our 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 require s financial resources (including the use of available cash or additional long-term debt) and 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. In 2012, we completed three acquisitions: OPTIMA, ERS, and Greywolf. These acquired businesses may not achieve as favorable financial results as we anticipated when we decided to make such acquisitons. These acquisitions and any future acquisition transactions 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.

 

The production volumes and profitability from our El Dorado, Arkansas, calcium chloride plant facility may not be as high as originally expected.

 

During late 2009 and early 2010, we completed the construction and began the operation of a calcium chloride plant facility near El Dora do, Arkansas. The plant’s anticipated profitability and the advantages we expect ed t o receive from the plant were based on many factors, including the level of production from the plant, our ability to improve the plant’s performance, sales prices to be received for the plant’s products, raw material and operating costs , and f uture demand for products. Given the plant’s production volumes and profitability to date, there can be no assurance that the El Dorado, Arkansas, plant’s future profitability will achieve original expectations.

 

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Our operations involve significant operating risks, and insurance covera ge may not be available or cost- effective.

 

We are subject to operating hazards normally associated with the oilfield service industry, including 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 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 them 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. Limits of insurance coverage we have purchased are consistent with the exposures we face and the nature of our products and services. Due to economic conditions in the insurance industry, from time to time, we have increased our self-insured retentions for certain policies in order to minimize the increased costs of coverage or we have reduced our limits of insurance coverage for, or not procured, named windstorm coverage. In certain areas of our business, we, from time to time, have elected to assume the risk of loss for specific assets. To the extent we suffer losses or claims that are not covered, or are only partially covered by insurance, our results of operations could be adversely affected.

 

We have technological and age-obsolescence risk, both with our products and services as well as with our equipment assets.

 

Competitors constantly evolve their technologies and methodologies and replace their used assets with new assets. If we are unable to adapt to new advances in technology or replace mature assets with new assets, we are at risk of losing customers and market share. In particular, many of our most significant equipment assets, including heavy lift barges and dive support vessels, are approaching the end of their useful lives, which may adversely affect our ability to serve certain customers. The permanent replacement or upgrade of any of our vessels will require significant capital. Due to the unique nature of many of these vessels, finding a suitable or acceptable replacement may be difficult and/or cost prohibitive. The replacement or enhancement of these vessels over the next several years may be necessary in order for the Offshore Services segment to effectively compete in the current marketplace.

 

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 or qualified 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 or on well abandonment and decommissioning work for our Maritech subsidiary.

 

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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 changes in the forecasts of the supply, demand, cost and timing of well abandonment and decommissioning services; damage to wells and infrastructure caused by hurricanes and other natural events; changes in governmental regulations governing well abandonment and decommissioning work; and other factors. In particular, a portion of the remaining decommissioning liabilities for our Maritech subsidiary relate to offshore production platforms that were toppled and destroyed during 2005 and 2008 hurricanes, and the estimates to perform the work on these properties is particularly imprecise due to the unusual nature of the w ork to be performed. During 2012 , Maritech adjusted its decommissioning liabilities, increa sing them by approximately $40.8 million, either for work performed during the year or related to adjusted estimates of the cost of future work to b e performed. T his adjustment was directly charged to earnings as an opera ting expense during 2012 . If the actual cost of future abandonment and decommissioning work is materially greater than our current estimates, such additional costs could have an additional adverse effect on earnings.

 

Weather- Related Risks

 

Certain of our operations are seasonal and depend, in part, on weather conditions.

 

The Offshore Services segment has historically enjoyed its highest vessel utilization rates during the period from April to October, when weather conditions are typically more favorable for offshore activities, and has experienced its lowest utilization rates in the period from November to March. This segment, under certain lump sum and other contracts, 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 frac water management services can be dependent on adequate water supplies that can be accessible to its customers. To the extent severe drought conditions prevent our onshore Fluids Division customers from accessing water supplies, frac water operations may become impractical, 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, rising water, 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.

 

A portion of the costs resulting from damages from the 2005 and 2008 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, debris removal, and platform construction associated with six offshore platforms that were destroyed by Hurricanes Rita and Ike during 2005 and 2008, respe ctively. As of December 31, 2012 , Maritech has remaining work associated with two of the downed platforms. The estimated cost to perform the remaining abandonment, decommissioning, and debris removal is approximately $13.9 million net to our interest before any insurance recoveries. 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 f uture periods. All of this $13.9 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.

 

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We have elected to self-insure windstorm damage to our remaini ng Maritech assets in the Gulf of Mexico , and hurricane damages could result in significant uninsured losses.

 

Despite the sale s of substantially all of Maritech’s oil and gas reserves during 2011 and 2012 , we have re maining decommissioning lia bilities of approximately $87.4 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 the remaining offshore platforms and associated wells are not decommissioned and abandoned prior to a windstorm occurring, Maritech would be exposed to lo sses 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.

 

There can be no assurance that futu re insurance coverage with favorable premiums and deductibles and maximum coverage amounts will be available in the market or that its cost will be justifiable. There can be no assurance that any windstorm insurance will be adequate to cover losses or liabilities associated with such windstorms. We cannot predict the continued availability of insurance or its availability at premium levels that justify its purchase.

 

Financial Risks

 

Significant deterioration of our financial ratios could result in covenant defaults under our long-term debt agreements and result in decreased credit availability.

 

As of December 31, 2012, our total debt outstanding was approximately $366.7 million, and our debt to total capital ratio was 41.4%. This debt to total capital ratio excludes approximately $74.0 million of available cash held as of December 31, 2012. Additional growth could result in increased debt levels to support our capital expenditure needs or acquisition activities. 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. Our long-term debt agreements contain customary covenants and other restrictions and requirements. In addition, the agreements require us to maintain certain financial ratio requirements. Significant deterioration of these ratios could result in a default under the agreements. The agreements also include cross-default provisions relating to any other indebtedness we have that is greater than a defined amount. If any such indebtedness is not paid or is accelerated and such event is not remedied in a timely manner, a default will occur under the long-term debt agreements. Any event of default, if not timely remedied, could result in a termination of all commitments of the lenders and an acceleration of any outstanding loans and credit obligations.

 

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-sized to medium-sized oil and gas operating companies that may be more susceptible to fluctuating oil and gas commodity prices or generally increased operating expenses than larger companies. Our ability to collect from our customers may be impacted by adverse changes in the energy industry.

 

As the owner and operator of certain oil and gas property interests, Maritech is liable for the proper abandonment and decommissioning of the wells, platforms, and pipelines, as well as the site clearance related to these properties. We have guaranteed a portion of the abandonment and decommissioning liabilities of Maritech. In certain instances, Maritech is entitled to be paid in the future for all or a portion of these obligations by the previous owner of the property once 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 to be 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 material losses.

 

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We may have continuing exposure on abandonment and decommissioning obligations associated with oil and gas properties sold 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 associated decommissioning lia bilities having a value at the time of sale of approximately $122.0 million pursuant to the purchase and sale agreements. For oil and gas properties for which Maritech was previously the operator, the buyer of the properties has now generally become the successor operator, and has assumed the financial responsibilities associated with the properties’ operations. 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 and we have insufficient other security, the previous owners and operators of the properties, including Maritech, may be required to assume responsibility for the abandonment and decommissioning obligation. To the extent Maritech is required to assume or perform a significant portion of the abandonment and decommissioning obligations associated with these sold oil and gas properties, our financial condition and results of operations may be negatively affected.

 

Our operating results and cash flows for certain of our subsi diaries 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, and the Mexican 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.

 

We are exposed to interest rate risk with regard to our indebtedness.

 

As of December 31, 2012, we have $51.2 million outstanding under our revolving credit facility. Our revolving credit facility consists of floating rate loans that bear interest at an agreed upon percentage rate spread 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.

 

The terms governing our revolving credit facility were agreed to in October 2010, and it is scheduled to mature in 2015. The terms governing our Senior Notes were agreed to in April 2006, April 2008, and October 2010. These Senior Notes all bear interest at fixed interest rates and are scheduled to mature at various dates between April 2013 and December 2020. 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.

 

Compressco Partners may not generate sufficient cash from operations to make cash distributions to its common and subordinated unitholders .

 

Compressco Partners may not generate sufficient cash from operations to enable it to make cash distributions to holders of common units at the minimum quarterly distribution rate under its cash distribution policy. To the extent Compressco Partners has insufficient available cash to distribute, the distribution shortfall will first be attributed to the subordinated units we hold, resulting in a reduction in our financing cash flows from distributions from Compressco Partners. Any shortfall in quarterly distributions attributed to the subordinated units will not be carried forward in arrears or recovered in future distributions.

 

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 strictly govern our operations relating to: corporate governance, employees, taxation, fees, filing requirements, permitting requirements, environmental affairs, health and safety, waste management, and the manufacture, storage, handling, transportation, use, and sale of chemical products. Certain international jurisdictions impose additional restrictions on our activities, such as currency restrictions, importation and exportation restrictions, and restrictions on labor practices. Our operation and decommissioning of offshore properties are also subject to and affected by various government regulations, including numerous federal and state environmental protection laws and regulations. These laws and regulations are becoming increasingly

 

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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, injunctions, or both. Third parties may also have the right to pursue legal actions to enforce compliance. It is possible that increasingly strict environmental laws, regulations, and enforcement policies could result in substantial costs and liabilities to us and could subject our handling, manufacture, use, reuse, or disposal of substances or pollutants to increased scrutiny.

 

The EPA is performing a study of 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. In addition, in December 2012, the EPA announced an update of the progress made pursuant to a study of the effects of hydraulic fracturing on the environment and reported that the full results of the study would be provided in 2014. 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, Compressco , and Fluids segments.

 

A large portion of Maritech’s remaining well abandonment and decommissioning operations are conducted on offshore federal leases and are governed by increasing U.S. gover nment regulations. During 2010, the BOEMRE issued formal Notice to Lessees (NTLs) and other safety regulations implementing additional safety and certification requirements applicable to drilling activities in the Gulf of Mexico. 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 require that permanent plugs be set in nearly 3,500 nonproducing wells and that 650 oil and gas production platforms be dismantled if they are no longer being used. In October 2011, the BOEMRE’s responsibilities were divided between the BO EM and the BSEE, which oversee s the provisions of the Idle Iron Guidance . Under limited circumstances, the BSEE could require Maritech to suspend or terminate its operations on a federal lease. The BOEM also establishes the basis for royalty payments due under federal oil and natural gas leases through regulations issued under applicable statutory authority.

 

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 f ederal 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 affect our business. 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 business 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, which may have a negative impact on our business. In addition to potential impacts on our business directly or in directly resulting from climate change legislation or regulations, our business also could be negatively affected by climate change - related physical changes or changes in weather patterns.

 

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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 the types of services offered by certain of 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 operat ions in, among other countries, Argentina, Brazil, Canada, Finland, Ghana, India, Mexico, Norway, Sweden, and the United Kingdom, and have operating joint ventures in Libya and Saudi Arabia . A portion of our planned future growth includes expansion into additional countries. Foreign operations carry special risks. Our business in the countries in which we currently operate and those in which we may operate in the future could be limited or disrupted by:

         restrictions on repatriating foreign profits back to the United States;

         the impact of anti-corruption laws and the risk that actions taken by us or others on our behalf may adversely affect our operations and competitive positio n in the affected countries;

         government controls and government actions, such as expropriation of assets and changes in legal and regulatory environments;

         import and export license requirements;

         political, social, or economic instability;

         trade restrictions;

         changes in tariffs and taxes; and

         the limited knowledge of these markets or the inability to protect our interests.

 

We and our affiliates operate in countries where governmental corruption has been known to exist. While we and our subsidiaries are committed to conducting business in a legal and ethical manner, there is a risk of violating either the U.S. Foreign Corrupt Practices Act (FCPA) 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 when we expect, our growth and profitability from international operations could be negatively affected.

 

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.

 

On December 15, 2009, the EPA published its final findings that emissions of carbon dioxide, methane , and other “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 atmosph ere 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 e xisting provisions of the CAA. The EPA rules regula te GHG emissions under the CAA and require a reduction in emissions of GHGs from motor vehicles and from ce rtain 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 oi l 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 to reduce emissions of GHGs associated with our operations. Further, Congress has considered and almost one-half of the states have adopted

 

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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.

   

Item 1B. Unresolved Staff Comments.

 

None.

 

Item 2. Properties.

 

Our properties consist primarily of our corporate headquarters facility, chemical plants, processing plants, distribution facilities, barge rigs, heavy lift and dive support vessels, well abandonment and decommissioning equipment, oil and gas properties, rig cooling equipment, and flow back production testing equipment . In addition, through our majority owned subsidiary, Compressco Partners, our properties include compression equipment. All obligations under the bank revolving credit facility for Compressco Partners are secured by a first lien security interest in substantially all of Compressco Partners’ assets, including its compressor fleet, but excluding its real property. The following information describes facilities that we leased or owned as of December   31,   2012 . We believe our facilities are adequate for our present needs.

 

Facilities

 

Fluids Division

 

Fluids Division facilities include seven active 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 con sist of 29 square miles of mineral acreage , solar evaporation ponds , and related production and storage facilities. In addition, the Fluids Division also owns and leases brine mineral reserves in Arkansas.

 

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 twenty-seven s ervice center facilities, sixteen in the United States and eleven internationally. The Fluids Division also leases eight offices and twenty-eight terminal locations, fourteen throughout the United States and fourteen internationally.

 

We also lease approximately 33,000 gross acres of bromine-containing brine reserves in Magnolia, Arkansas. We hold these assets for possible future development and to provide a security of supply for our bromine and other raw materials.

 

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Production Enhancement Division

 

The Production Testing segment conducts its operations through thirteen production testing service centers (twelve of which are leased) in the U.S., located in Colorado, Louisiana, North Dakota, Oklahoma, Pennsylvania , Texas, West Virginia, and Wyoming. In addition, the Production Testing segment has leased facil ities in Brazil, Mexico, Libya, United Arab Emirates, Ghana, Angola, Saudi Arabia, Iraq, Argentina, Australia, Canada, United Kingdom, and Colombia. The Compressco segment’s facilities include an owned fabrication facility and a leased headquarters facility in Oklahoma, a leased fabrication facility in Alberta, Canada, a leased service and sales facility in New Mexico, leased service facilities in Argentina, California, and Mexico, and sales offices in California, Canada, Colorado, Louisiana , New Mexico , Oklahoma, Pennsylvania, and Texas .

 

Offshore Division

 

The Offshore Division condu cts its operations through six offices and service facility locations (five 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:

 

TETRA Hedron

Derrick barge with 1,600-ton fully revolving crane

TETRA Arapaho

Derrick barge with 800-ton capacity crane

TETRA DB-1

Derrick barge with 615-ton capacity crane

Epic Explorer

210-foot dive support vessel with saturation diving system

Epic Seahorse

210-foot dive support vessel

 

In addition, the Adams Challenge is under chartered lease arrangement by th e Offshore Division through October 2013, with an option to extend for an additional 12 months. The Adams Challenge is a 280-foot dynamically positioned dive support vessel with a 1,000-foot saturation diving system. One of our vessels, the TETRA DB-1, has recently been idled due to decreased demand in the shallower waters of the Outer Continental Shelf in the Gulf of Mexico in which it has historically operated. The Offshore Services segment is pursuing the sale of this vessel.

 

See below for a discussion of the Offshore Division’s oil and gas property assets.

 

Corporate

 

Our headquarters are located in The Woodlands, Texas, in a 153,000 square foot office building, which is located on 2.635 acres of land. In December 2012, we entered into a sale leaseback transaction whereby we sold the headquarters building and land for a sale price of $43.8 million before transaction costs and other deductions, and leased back the facility for an initial lease term of 15 years. In addition, we own a 28 ,000 square foot technical facility to service our Fluids Division operations.

 

Oil and Gas Properties

 

The following tables show, for the periods indicated, operating information related to our Maritech subsidiary’s oil and gas interests, all of which are located in the U.S. Gulf of Mexico. Maritech’s oil and gas operations are a separate segment included within our Offshore Division.

 

See also “Note R – Supplemental Oil and Gas Disclosures” in the Notes to Consolidated Financial Statements for additional information.

 

Oil and Gas Reserves

 

Following the 2011 and 2012 sale s of substantially all of Maritech’s proved oil and gas reserves , Maritech’s remaining oil and gas reserves as of December 31, 2012, are negligible and not material to our business operations or financial position.

 

24

 

Production Information

 

The table below sets forth information related to production, average sales price, and average production cost per unit of oil and gas produced during 2012, 2011, and 2010 :

 

 

Year Ended December 31,

 

2012

 

2011

 

2010

Production:

 

 

 

 

 

 

 

 

 

 

 

Natural gas (Mcf)

 

310,894  

 

 

 

3,321,651  

 

 

 

7,065,258  

 

NGL (Bbls)

 

38,681  

 

 

 

88,070  

 

 

 

132,191  

 

Oil (Bbls)

 

23,040  

 

 

 

611,748  

 

 

 

1,360,126  

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues:

 

 

 

 

 

 

 

 

 

 

 

Natural Gas

$

1,609,000  

 

 

$

14,596,000  

 

 

$

60,416,000  

 

NGL

 

1,907,000  

 

 

 

4,744,000  

 

 

 

6,003,000  

 

Oil

 

2,641,000  

 

 

 

62,601,000  

 

 

 

131,422,000  

 

Total

$

6,157,000  

 

 

$

81,941,000  

 

 

$

197,841,000  

 

 

 

 

 

 

 

 

 

 

 

 

 

Average realized unit prices and production costs:

 

 

 

 

 

 

 

 

 

 

 

Natural gas (per Mcf)

$

5.18  

 

 

$

4.39  

 

 

$

8.55  

 

NGL (per Bbl)

$

49.30  

 

 

$

53.87  

 

 

$

45.41  

 

Oil (per Bbl)

$

114.63  

 

 

$

102.34  

 

 

$

96.62  

 

 

 

 

 

 

 

 

 

 

 

 

 

Production cost per equivalent barrel

$

33.02  

 

 

$

26.72  

 

 

$

26.62  

 

Depletion cost per equivalent barrel

$

 

 

 

$

22.05  

 

 

$

27.60  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Realized unit prices during 2010 and 2011 include the impact of hedge commodity swap contracts. In April 2011, in connection with the anticipated plans to sell Maritech’s remaining oil and gas properties, we liquidated the derivative swap financial instruments that were designated as hedges of Maritech’s future oil production. Equivalent barrel (BOE) information is calculated assuming six Mcf of gas is equivalent to one barrel of oil. Insurance recoveries during 2010 totaled approximately $2.5 million and are excluded from production cost per equivalent barrel for the year. Depletion cost per equivalent barrel excludes the impact of dry hole costs and property impairments.

 

Acreage and Productive Wells

 

At December 31, 2012 , our Maritech subsidiary owned interests in the following oil and gas wells and acreage:

 

 

Productive Gross

 

Productive Net

 

Developed

 

Undeveloped

 

 

Wells

 

Wells

 

Acreage

 

Acreage

 

State/Area

Oil

 

Gas

 

Oil

 

Gas

 

Gross

 

Net

 

Gross

 

Net

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Louisiana Onshore

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Louisiana Offshore

 

 

4  

 

 

 

1.3  

 

 

 

 

 

1,187  

 

594  

 

Texas Onshore

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Texas Offshore

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Federal Offshore

 

 

 

 

 

 

 

 

26,875  

 

12,463  

 

31,809  

 

15,116  

 

Total

 

 

4  

 

 

 

1.3  

 

26,875  

 

12,463  

 

32,996  

 

15,710  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The majority of Maritech’s oil and gas properties are held by production. Leases covering undeveloped acreage other than acreage held by production have ex piration terms ranging from 2013 through 2015. The following table sets forth the expiration amounts of our gross and net undeveloped acreage as of December 31, 2012 :

 

25

 

 

 

 

 

 

 

 

 

 

 

 

Held by

 

2013

 

2014

 

2015

 

2016

 

2017

 

Production

State/Area

Gross

Net

 

Gross

Net

 

Gross

Net

 

Gross

Net

 

Gross

Net

 

Gross

Net

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Louisiana Onshore

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Louisiana Offshore

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

1,187  

594  

Texas Offshore

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Federal Offshore

 

 

 

 

 

 

1,250  

1,250  

 

 

 

 

 

 

 

57,434  

26,329  

Total

 

 

 

 

 

 

1,250  

1,250  

 

 

 

 

 

 

 

58,621  

26,923  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Maritech has no significant delivery commitments with regard to its future oil and gas production.

 

Drilling Activity

 

During 2012, Maritech did not participate in drilling activity. During 2011 , Maritech p articipated in the drilling of 4 gross development wells (0.8 net wells) , all of which were productive. During 20 10 , Maritech p articipated in the drilling of 6 gross development wells (4.32 net wells) and two gross exploratory wells (1.5 net wells), 7 of which were pro ductive. As of December 31, 2012 , there were no wells in the process of being drilled.

 

Significant Oil and Gas Properties

 

As of December 31, 2012, Maritech has sold all of its most significant oil and gas producing properties and is in the process of selling all of its remaining oil and gas producing properties. These remaining oil and gas properties are classified as Oil and Gas Properties Held for Sale in our accompanying consolidated balance sheet as of December 31, 2012. Prior to their sale, Maritech’s most significant oil and gas properties were its interests in the Timbalier Bay Area, the Main Pass Area, and the East Cameron 328 field. Production information for each of these most significant properties during the thr ee years ended December 31, 2012 , is as follows:

 

 

Year Ended December 31,

 

2012

 

2011

 

2010

 

Oil

NGL

Natural Gas

 

Oil

NGL

Natural Gas

 

Oil

NGL

Natural Gas

 

(MBbls)

(MBbls)

(MMcf)

 

(MBbls)

(MBbls)

(MMcf)

 

(MBbls)

(MBbls)

(MMcf)

Timbalier Bay Area

 

 

 

 

379  

31  

1,549  

 

555  

25  

912  

Main Pass Area

 

 

 

 

53  

22  

862  

 

87  

35  

2,362  

East Cameron 328

 

 

 

 

61  

 

32  

 

213  

 

132  

 

 

 

 

 

 

 

 

 

 

 

 

 

Average realized unit prices and production costs for each of these fields were approximately equal to Maritech’s overall unit prices and costs, as all of Maritech’s production is located in the Gulf of Mexico region.

 

Item 3 . Legal Proceedings.

 

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 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.

 

26

 

PART II

 

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

 

Price Range of Common Stock

 

Our common stock is traded on the New York Stock Exchange under the symbol “TTI.” As of March 1, 2013 , there were approximately 9,205 holders of record of the common stock. The following table sets forth the high and low sale prices of the common stock for each calendar quarter in the two years ended December 31, 201 2 , as reported by the New York Stock Exchange.

 

 

High

 

Low

2012

 

 

 

 

 

 

 

First Quarter

$

10.66  

 

 

$

8.69  

 

Second Quarter

 

9.80  

 

 

 

6.09  

 

Third Quarter

 

7.57  

 

 

 

6.00  

 

Fourth Quarter

 

7.75  

 

 

 

5.35  

 

 

 

 

 

 

 

 

 

2011

 

 

 

 

 

 

 

First Quarter

$

15.57  

 

 

$

10.41  

 

Second Quarter

 

16.00  

 

 

 

11.63  

 

Third Quarter

 

13.45  

 

 

 

7.71  

 

Fourth Quarter

 

10.53  

 

 

 

6.77  

 

 

Market Price of Common Stock

 

The following graph compares the five-year cumulative total returns of our common stock, the Standard & Poor’s 500 Composite Stock Price Index (S&P 500) , and the Philadelphia Oil Service Sector Index (PHLX Oil Service Sector), assuming $100 invested in each stock or index on December 31, 2007 , all dividends reinvested, and a fiscal year ending December 31. This information shall be deemed furnished, and not filed, in this Form 10-K and shall not be deemed incorporated by reference into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934 as a result of this furnishing, except to the extent we specifically incorporate it by reference.

 

 

27


Dividend Policy

 

We have never paid cash dividends on our common stock. We currently intend to retain earnings to finance the growth and development of our business. Any payment of cash dividends in the future will depend upon our financial condition, capital requirements, and earnings, as well as other factors the Board of Directors may deem relevant. We declared a dividend of one Preferred Stock Purchase Right per share of common stock to holders of record at the close of business on November 6, 1998. See “Note T – Stockholders’ Rights Plan” in the Notes to Consolidated Financial Statements attached hereto for a description of such Rights. See “Management’s Discussion and Analysis of Financial Condition and Results of Operation – Liquidity and Capital Resources” for a discussion of potential restrictions on our ability to pay dividends.

 

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

 

In January 2004, our Board of Directors authorized the repurchase of up to $20 million of our common stock. Purchases may be made from time to time in open market transactions at prevailing market prices. The repurchase program may continue until the authorized limit is reached, at which time the Board of Directors may review the option of increasing the authorized limit. During 2004 through 2005, we repurchased 340,950 shares of our common stock pursuant to the repurchase program at a cost of approximately $5.7 million. There were no repurchases made during 2006 through 2012 pursuant to the repurchase program. Shares repurchased during the fourth quarter of 2012 other than pursuant to our repurchase program are as follows:

 

 

 

 

 

 

 

 

 

 

 

 

Maximum Number (or

 

 

 

 

 

 

Average

 

 

Total Number of Shares

 

 

Approximate Dollar Value) of

 

 

 

Total Number

 

 

Price

 

 

Purchased as Part of

 

 

Shares that May Yet be

 

 

 

of Shares

 

 

Paid per

 

 

Publicly Announced

 

 

Purchased Under the Publicly

 

Period

 

Purchased

 

 

Share

 

 

Plans or Programs (1)

 

 

Announced Plans or Programs (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oct 1 – Oct 31, 2012

 

448  

(2)

 

$

5.71  

 

 

 

 

$

14,327,000

 

Nov 1 – Nov 30, 2012

 

6,323  

(2)

 

 

6.70  

 

 

 

 

 

14,327,000

 

Dec 1 – Dec 31, 2012

 

3,219  

(2)

 

 

7.29  

 

 

 

 

 

14,327,000

 

Total

 

9,990  

 

 

 

 

 

 

 

 

$

14,327,000

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 


(1)

In January 2004, our Board of Directors authorized the repurchase of up to $20 million of our common stock. Purchases will be made from time to time in open market transactions at prevailing market prices. The repurchase program may continue until the authorized limit is reached, at which time the Board of Directors may review the option of increasing the authorized limit.

(2)

Shares we received in connection with the exercise of certain employee stock options or the vesting of certain employee restricted stock. These shares were not acquired pursuant to the stock repurchase program.

 

Item 6. Selected Financial Data.

 

The following tables set forth our selected consolidated financial data for the years ended December 31, 2012 , 2011 , 2010 , 2009 , and 2008 . The selected consolidated financial data does not purport to be complete and should be read in conjunction with, and is qualified by, the more detailed information, including the Consolidated Financial Statements and related Notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operation” appearing elsewhere in this report. Please read “Item 1A. Risk Factors” beginning on page 12 for a discussion of the material uncertainties which might cause the selected consolidated financial data not to be indicative of our future financial condition or results of operations . During 2008, Maritech acquired certain oil and gas properties. During 2012, our Production Testing segment acquired OPTIMA, ERS, and Greywolf. During 2008, we recorded significant impairments of oil and gas properties, goodwill, and other long-lived assets. During 2010, we recorded significant impairments of our oil and gas properties, a dive support vessel, and a calcium chloride manufacturing plant, as well as significant charges to earnings associated with adjustments to Maritech’s decommissioning liabilities.  During 2011, Maritech sold approximately 95% of the oil and gas proved reserves it held as of December 31, 2010. These acquisitions, dispositions, and impairments significantly impact the comparison of our financial statements for 2012 to earlier years.

 

28

 

 

Year Ended December 31,

 

 

2012

 

2011

 

2010

 

2009

 

2008

 

 

(In Thousands, Except Per Share Amounts)

 

Income Statement Data

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

$

880,831  

 

 

$

845,275  

 

 

$

872,678  

 

 

$

878,877  

 

 

$

1,009,065  

 

 

Gross profit

 

168,869  

 

 

 

90,510  

 

 

 

43,707  

 

 

 

213,097  

 

 

 

152,001  

 

 

General and administrative expense

 

133,138  

 

 

 

113,273  

 

 

 

100,132  

 

 

 

100,832  

 

 

 

104,949  

 

 

Interest expense

 

17,378  

 

 

 

17,195  

 

 

 

17,528  

 

 

 

13,207  

 

 

 

17,557  

 

 

Interest income

 

(298)

 

 

 

(756)

 

 

 

(224)

 

 

 

(417)

 

 

 

(779)

 

 

Other (income) expense, net

 

(9,532)

 

 

 

(45,435)

 

 

 

64  

 

 

 

(5,895)

 

 

 

(12,884)

 

 

Income (loss) before discontinued

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

operations

 

18,754  

 

 

 

5,482  

 

 

 

(43,325)

 

 

 

68,807  

 

 

 

(9,655)

 

 

Net income (loss)

 

18,757  

 

 

 

5,418  

 

 

 

(43,718)

 

 

 

68,804  

 

 

 

(12,136)

 

 

Net income (loss) attributable to

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

TETRA stockholders

$

15,960  

 

 

$

4,147  

 

 

$

(43,718)

 

 

$

68,804  

 

 

$

(12,136)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (loss) per share, before

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

discontinued operations attributable

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

to TETRA stockholders

$

0.21  

 

 

$

0.05  

 

 

$

(0.57)

 

 

$

0.92  

 

 

$

(0.13)

 

 

Average shares

 

77,293  

 

 

 

76,616  

 

 

 

75,539  

 

 

 

75,045  

 

 

 

74,519  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (loss) per diluted share,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

before discontinued operations

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

attributable to TETRA stockholders

$

0.20  

 

 

$

0.05  

 

 

$

(0.57)

 

 

$

0.91  

 

 

$

(0.13)

 

 

Average diluted shares

 

77,963  

 

(1)

 

77,991  

 

(2)

 

75,539  

 

(3)

 

75,722  

 

(4)

 

74,519  

 

(3)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 


(1)

F or the year ended December 31, 2012 , the calculation of average diluted shares outstanding excludes the impact of 2,832,192 average outstanding stock options that would have been antidilutive.

(2 )

F or the year ended December 31, 2011 , the calculation of average diluted shares outstanding excludes the impact of 2,831,118 average outstanding stock options that would have been antidilutive.

(3 )

For the years ended December 31, 2008 and 2010, the calculation of average diluted shares outstanding excludes the impact of all of our outstanding stock options, since all were antidilutive due to the net loss for the periods.

(4 )

For the year ended December 31, 2009, the calculation of average diluted shares outstanding excludes the impact of 3,185,388 average outstanding stock options that would have been antidilutive.

 

 

December 31,

 

2012

 

2011

 

2010

 

2009

 

2008

 

(In Thousands)

Balance Sheet Data

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Working capital

$

178,294  

 

 

$

296,136  

 

 

$

198,106  

 

 

$

148,343  

 

 

$

222,832  

 

Total assets

 

1,261,818  

 

 

 

1,203,310  

 

 

 

1,299,628  

 

 

 

1,347,599  

 

 

 

1,412,624  

 

Long-term debt

 

331,268  

 

 

 

305,000  

 

 

 

305,035  

 

 

 

310,132  

 

 

 

406,840  

 

Decommissioning and other

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

long-term liabilities

 

80,427  

 

 

 

96,857  

 

 

 

261,438  

 

 

 

218,498  

 

 

 

277,482  

 

Equity

 

593,308  

 

 

 

569,088  

 

 

 

516,323  

 

 

 

576,494  

 

 

 

515,821  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation.

 

The following discussion is intended to analyze major elements of our consolidated financial statements and provide insight into important areas of management’s focus. This section should be read in conjunction with the Consolidated Financial Statements and the accompanying Notes included elsewhere in this Annual Report.

 

Statements in the following discussion may include forward-looking statements. These forward-looking statements involve risks and uncertainties. See “Item 1A. Risk Factors,” for additional discussion of these factors and risks.

 

29

 

Business Overview 

 

During 2012, we continued to pursue our strategy for growth in a market environment characterized by high oil prices, comparatively low domestic natural gas prices, recovering Gulf of Mexico activity levels, an emergence of attractive international contracts, and continuing overall economic uncertainty. In response to each of these market factors, we initiated or continued strategic efforts to capitalize on specific growth opportunities. The most significant of these market developments continues to be the strength of domestic onshore shale reservoir activity. While the growth levels of certain shale reservoir fields have crested, activity levels in the Eagle Ford, Bakken, Niobrara, and Permian Basin fields have remained robust. As part of our efforts to strategically expand the markets served by our Production Testing segment during 2012, we acquired the assets and operations of Eastern Reservoir Services (ERS), and Greywolf Production Systems, Inc. and GPS Ltd. (together Greywolf). These acquisitions contributed significant growth for our Production Testing segment and allow the segment to capture a greater share of the domestic and Canadian markets . Also, in response to continuing strong shale reservoir activity, our Fluids Division has organically expanded its domestic onshore operations to serve the demand for its frac water management services. The strength of domestic and Canadian crude oil and liquids prices has also led our Compressco segment to continue its focus on expanding its capacity to provide unconventional compression applications as a compliment to its significant dry gas production enhancement services. In the U.S. Gulf of Mexico, government restrictions and delays in obtaining regulatory permits have eased somewhat and have resulted in a return to pre-Macondo activity levels. Our Fluids Division has capitalized on this growth, resulting in significant increases in its deepwater offshore clear brine fluids (CBF) sales activity. However, the U.S. Gulf of Mexico well abandonment and decommissioning market remains challenging for our Offshore Services segment, and we have implemented cost reduction and asset rationalization efforts to improve the focus and efficiency of this segment. Outside of the United States, we are exploiting unique opportunities for many of our businesses. Our Compressco segment continues to grow its Latin America operations, while also continuing to pursue other international opportunities. Our Production Testing segment expanded its scope of services and international presence with the acquisition of Optima Solutions Holding Limited (OPTIMA), an Aberdeen, Scotland-based provider of offshore rig cooling services and associated products that suppress heat generated by high-rate flaring of hydrocarbons during well test operations. Our Production Testing and Fluids segments have each also expanded their Eastern Hemisphere operations through new service contracts and additional activity under existing service contracts, particularly in the Middle East.

 

Our consolidated revenues and gross profit for the year ended December 31, 2012, reflect the growth of our Production Testing, Compressco, and Fluids segments, each of which achieved record revenue levels during 2012. In particular, the results of our Production Testing segment for 2012 include the impact of its acquisitions of OPTIMA, ERS, and Greywolf. During 2012, these acquisitions contributed aggregate revenues of $62.2 million and income before taxes, net of $2.8 million of transaction costs, of $6.2 million. Our Compressco segment also reflected growth in revenues and profitability during 2012 compared to 2011, primarily as a result of the increased Latin America activity, but also due to the growth of its domestic unconventional application services. Our Fluids Division also reported increased revenues and profitability compared to 2011, primarily due to the increased CBF product sales from increased activity in the Gulf of Mexico and from increased services revenues and profits from its growing domestic frac water management operation. These increases in Fluids Division CBF and services revenues more than offset the decreased revenues from its manufactured products operation. Partially offsetting the growth in these segments, our Offshore Services segment reported decreased revenues during 2012 compared to 2011 due to a number of factors, including weather disruptions, customer project delays, and pricing pressures. Following the sales of its oil and gas producing properties, our Maritech segment now generates minimal revenues. Increased consolidated gross profit was partially offset by increased consolidated general and administrative expense, primarily due to the above mentioned acquisitions.

 

Despite spending an aggregate of approximately $163.3 million on acquisitions and an additional $107.5 million on capital expenditures during 2012, our balance sheet remains strong. The majority of the funding for this growth was provided from available cash, and of the $88.4 million of cash that was borrowed during 2012, $28.6 million was repaid by year-end. Our asset review efforts contributed approximately $59.3 million in cash from the sale of certain assets, including the sale and leaseback of our corporate headquarters facility. Cash provided from operations during 2012 was approximately $17.7 million, as our focus on cash generation during the fourth quarter, including improved accounts receivable collections, helped offset the significant expenditures to extinguish Maritech’s remaining decommissioning liabilities during the year.   Despite the sale of the Maritech properties in 2011 and 2012, we continue to utilize a significant portion of our operating cash flows to extinguish Maritech’s remaining decommissioning liabilities. We expended approximately $ 94.4 million on decommissioning work performed during 2012, and a majority of the remaining decommissioning liability is anticipated to be extinguished during 2013. As of December 31, 2012, we had a consolidated cash balance of approximately $74.0 million,

 

30

 

although approximately $13.0 million of the balance is on Compressco Partners’ balance sheet to satisfy its operating requirements as well as to fund quarterly distributions pursuant to its partnership agreement. Subsequent to December 31, 2012, we repaid approximately $38.0 million of our outstanding balance under our revolving credit facility, and as of March 1, 2013, we had approximately $256.3 million available under the facility . As a result of our strong balance sheet, we remain focused on the growth priorities for our core service businesses, including the pursuit of additional acquisitions and funding the ongoing growth capital needs of our segments.

 

Future demand for our products and services depends primarily on activity in the oil and natural gas exploration and production industry, particularly including the level of expenditures for the exploration and production of oil and natural gas reserves and for the plugging and decommissioning of abandoned offshore oil and natural gas properties. The growth of certain of our businesses may become hampered by the current pricing levels of natural gas, particularly as compared to crude oil. However, we believe that there are growth opportunities for our products and services in the U.S. and foreign markets, supported primarily by:

         applications for many of our products and services in the continuing exploitation and development of shale reservoirs;

         increased regulatory requirements governing the abandonment and decommissioning work on aging offshore platforms and wells in the Gulf of Mexico;

         increases in technologically driven deepwater oil and gas well completions in the Gulf of Mexico; and

         increasing international oil and gas exploration and development activities.

 

Our Fluids Division generates revenues and cash flows by manufacturing and marketing clear brine completion fluids (CBFs), 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 Fluids Division also provides a broad range of associated services, including : onsite fluids filtration, handling, and recycling; wellbore cleanup; f luid engineering consultation; and fluid management services; as well as domestic onshore frac water management services. In addition, the Fluids Division also markets liquid and dry calcium chloride products manufactured at its production facilities or purchased from third-party suppliers t o a variety of markets outside the energy industry . Fluids D ivision revenues increased $30.0 million during 2012 compared to 2011, primarily due to increased CBF product sales from increased activity in the Gulf of Mexico, as permitting activity has increased compared to the prior year. Although demand levels for the Fluids Division’s CBF products are driven primarily by completion activity rather than drilling activity, the increase in the Gulf of Mexico rig count during late 2012 to pre-Macondo levels reflects the increasing demand for offshore CBF products, which steadily increased during 2012. Demand may continue to be affected by future regulatory restrictions. We anticipate continued increa ses in industry spending in 2013 , particularly given the current levels of crude oil prices. Also, continu ing to capitalize on the industry trend toward developing unconventional onshore shale reservoirs, the Fluids Division has expanded its onshore frac water management operation, which also contributed to increased revenues and profitability during 2012 .

 

Our Production Enhancement Division consists of two operating segments: the Production Testing segment and the Compressco segment. The Production Testing segment generates revenues and cash flows by performing after- frac flow back , production well testing , offshore rig cooling, and other associated services . The primary markets served by the Production Testing segment include many of the major oil and gas producing regions in the United States, Mexico , and Canada, as well as in certain oil and gas basins in certain regions in South America, Africa, Europe, the Middle East, and Australia . The Division’s production testing operations are generally driven by the demand for natural gas and oil and the resulting drilling and completion activities in the markets where the Production Testing segment serves. The Production Testing segment’s revenues increased significantly by $68.2 million in 2012 compared to 2011 , primarily due to the acquisitions of OPTIMA, ERS, and Greywolf during 2012, and due to increased activity in unconventional shale reservoirs. The Production Testing segment anticipate s that revenues w ill continue to increase in 2013 compared to 2012, primarily as a result of the 2012 acquisitions .

 

Compressco generates revenues and ca sh flows by performing compression-based production enhancement services throughout many of the onshore oil and gas producing regions of the United States, as well as certain basins in Mexico and Canada, and certain countries in South America, Eastern Europe, and the Asia -Pacific region . The Compressco segment provides services that are used in both conventional wellhead compression applications and unconventional compression applications, and in certain circumstances, well monitoring and sand separation services. Compressco segment revenues increased $13.7 million in 2012 as compared to 2011, primarily due to increased service revenues resulting from increased demand , particularly in Latin America, partially offset by a decrease in sales of compressor units. While there are uncertainties in Latin America that could affect operations, including the renewal of certain customer contracts, as well as uncertainties

 

31

 

surrounding the domestic price of natural gas which drives demand for a portion of Compressco’s domestic services, we expect revenues from the segment will continue to increase.

 

Our Offshore Division consists of two operating segments: Offshore Services and Maritech. Offshore Services generates revenues and cash flows by performing (1) downhole and subsea oil and gas well plugging and abandonment 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 saturated air diving services. The services provided by the Offshore Services segment are marketed to offshore operators primarily in the U.S. Gulf Coast region. Gulf of Mexico platform decommissioning and well abandonment activity levels are driven primarily by BSEE regulations; the age of producing fields; production platforms and other structures; oil and natural gas commodity prices; sales activity of mature oil and gas producing properties; and overall oil and gas company activity levels. Offshore Services revenues decreased by $21.4 million during 2012 compared to 2011, due to a number of factors including decreased work performed for Maritech, decreased diving, abandonment, and cutting services activity, customer project delays, weather disruptions, pricing pressures, and the sales of certain operations during the past year. In addition, the profitability of our Offshore Services segment was affected by approximately $8.4 million of impairments, primarily related to the decision to sell one of its heavy lift derrick barges due to decreased demand in the shallow waters in which it has historically operated. However, the Offshore Services segment anticipates increased profitability going forward compared to 2012 as a result of cost reduction and asset rationalization initiatives which began during the latter part of 2012.

 

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. As part of this strategic decision, beginning in 2011, Maritech began selling oil and gas property packages to industry participants and other thir d parties. Maritech is continuing to seek the sale of its remaining oil and gas producing properties during 2013 . As a result of these sales of oil and gas properties, Maritech’s revenues during 2012 decreased by $76.6 million compared to 2011 and are expected to continue to be minimal going forward . Maritech ’s current operations primarily consist of the ongoing plugging, abandonment, and decommissioning associated with its remaining offshore wells, facilities, and production platforms, and we expect to complete the majority of this remaining work during 2013 .

 

Critical Accounting Policies and Estimates

 

This discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements. We prepared these financial statements in conformity with United States generally accepted accounting principles. In preparing our consolidated financial statements, we make assumptions, estimates, and judgments that affect the amounts reported. We base these estimates on historical experience, available information, and various other assumptions that we believe are reasonable. We periodically evaluate these estimates and judgments, including those related to potential impairments of long-lived assets (including goodwill), the collectability of accounts receivable, and the current cost of future abandonment and decommissioning obligations. “Note B – Summary of Significant Accounting Policies” to the Consolidated Financial Statements contains the accounting policies governing each of these matters. The fair values of portions of our total assets and liabilities are measured using significant unobservable inputs. The combination of these factors forms the basis for our judgments made about the carrying values of assets and liabilities that are not readily apparent from other sources. These judgments and estimates may change as new events occur, as new information is acquired, and as changes in our operating environment are encountered. Actual results are likely to differ from our current estimates, and those differences may be material. The following critical accounting policies reflect the most significant judgments and estimates used in the preparation of our financial statements.

 

Impairment of Long-Lived Assets

 

The determination of impairment of long-lived assets is conducted periodically whenever 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 operating cash flows to be generated from these assets throughout their estimated useful lives. If an impairment of a long-lived asset is warranted, we estimate the fair value of the asset based on a present value of these cash flows or the value that could be realized from disposing of the asset in a transaction between market participants. The oil and gas industry is cyclical, and our estimates of the amount of future cash flows, the period over which these estimated future cash flows will be generated, as well as the fair value of an impaired asset, are imprecise. Our failure to accurately estimate these future operating cash flows or fair values could result in certain long-lived assets being overstated, which could result in impairment charges in periods

 

32

 

subsequent to the time in which the impairment indicators were first present. Alternatively, if our estimates of future operating cash flows or fair values are understated, impairments might be recognized unnecessarily or in excess of the appropriate amounts. Although the majority of our impairments of long-lived assets have typically related to oil and gas properties, during 2012 we recorded other long-lived asset impairments of $8.4 million. Given the current uncertain economic environment, the likelihood of additional material impairments of long-lived assets in future periods is higher due to the possibility of decreased demand for our products and services.

 

Impairment of Goodwill

 

The impairment of goodwill is also assessed whenever impairment indicators are present, but not less than once annually. Beginning in 2011, the annual assessment for goodwill impairment begins with a qualitative assessment of whether it is “more likely than not” that the fair value of each reporting unit is less than its carrying value. This qualitative assessment requires the evaluation, based on the weight of evidence, of the significance of all identified events and circumstances for each reporting unit. Based on this qualitative assessment, we determined that it was not “more likely than not” that the fair values of any of our reporting units were less than their carrying values as of December 31, 2012. If 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 would consist of a two-step accounting test performed on a reporting unit basis. If the carrying amount of the reporting unit exceeds its estimated fair value, an impairment loss is calculated by comparing the carrying amount of the reporting unit’s goodwill to our estimated implied fair value of that goodwill. Our estimates of reporting unit fair value , if required, are imprecise and are subject to our estimates of the future cash flows of each business and our judgment as to how these estimated cash flows translate into each business’ estimated fair value. These estimates and judgments are affected by numerous factors, including the general economic environment at the time of our assessment, which affects our overall market capitalization. If we over estimate the fair value of our reporting units, the balance of our goodwill asset may be overstated. Alternatively, if our estimated reporting unit fair values are understated, impairments might be recognized unnecessarily or in excess of the appropriate amounts.

 

Decommissioning Liabilities

 

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. These well abandonment and decommissioning liabilities (referred to as decommissioning liabilities) are recorded net of amounts allocable to joint interest owners and any contractual amounts to be paid by the previous owners of the property. In estimating the decommissioning liabilities, we perform detailed estimating procedures, analysis, and engineering studies. Whenever practical, Maritech settles these decommissioning liabilities by utilizing the services of its affiliated companies to perform well abandonment and decommissioning work. This practice saves us the profit margin that a third party would charge for such services. When these services are performed by an affiliated company, all recorded intercompany revenues are eliminated in the consolidated financial statements. Any difference between our own internal costs to settle the decommissioning liability and the recorded liability is recognized in the period in which we perform the work. The recorded decommissioning liability associated with a specific property is fully extinguished when the property is completely abandoned. Once a Maritech well abandonment and decommissioning project is performed, any remaining decommissioning liability in excess of the actual cost of the work performed is recorded as a gain and is included in earnings in the period in which the project is completed. Conversely, estimated or actual costs in excess of the decommissioning liability are charged against earnings in the period in which the work is estimated or performed.

 

We review the adequacy of our decommissioning liabilities whenever indicators suggest that either the amount or timing of the estimated cash flows underlying the liabilities have changed materially. The amount of cash flows necessary to abandon and decommission the property is subject to changes due to seasonal demand, increased demand following hurricanes, regulatory changes, and other general changes in the energy industry environment. Accordingly, the estimation of our decommissioning liabilities is imprecise. Maritech has adjusted its decommissioning liabilities during 2011 and 2012 as a result of increased estimates, as well as a result of the cost of significant abandonment and decommissioning work performed during the year. Maritech recorded approximately $ 40.8 and $ 78.4 million of excess dec ommissioning expense during 2012 and 2011 , respectively, associated with work performed or to be performed on nonproductive oil and gas properties. In addition, adjustments to decommissioning liabilities associated with productive properties were capitalized to oil and gas properties and contributed significantly to Marite ch recording approxima tely $15.2 m illion of oil and gas property impairments duri ng 2011 . The estimation of the decommissioning liabilities associated with the two remaining Maritech offshore platforms that were destroyed during the 2005 and 2008 hurricanes is particularly difficult due to the non-routine nature of the efforts required. The actual cost of performing Maritech’s well abandonment and

 

33

 

decommissioning work has often exceeded our initial estimate of Maritech’s decommissioning liabilities and has resulted in charges to earnings in the period the work is performed or when the additional liability is determined. To the extent our decommissioning liabilities are understated, additional charges to earnings may be required in future periods.

 

Revenue Recognition

 

We generate revenue on certain well abandonment and decommissioning projects under contracts which are typically of short duration and that provide for either lump-sum charges or specific time, material, and equipment charges, which are billed in accordance with the terms of such contracts. With regard to lump sum contracts, revenue is recognized using the percentage-of-completion method based on the ratio of costs incurred to total estimated costs at completion. The estimation of total costs to be incurred may be imprecise due to unexpected well conditions, delays, weather, and other uncertainties. Inaccurate cost estimates may result in the revenue associated with a specific contract being recognized in an inappropriate period. Total project revenue and cost estimates for lump sum contracts are reviewed periodically as work progresses, and adjustments are reflected in the period in which such estimates are revised. Provisions for estimated losses on such contracts are made in the period such losses are determined. Despite the uncertainties associated with estimating the total contract cost, our recognition of revenue associated with these contracts has historically been reasonable.

 

Our Production Testing segment is party to a South American technical management contract which contains multiple deliverables, including the delivery of equipment and the performance of service milestones. While the contract provides contract-determined values associated with each deliverable, the recognition of revenue is determined based on the realized market values received by the customer as well as by the realizability of collections under the contract. The determination of realized market values is supported by objective evidence whenever possible, but may also be determined based on our judgments as to the value of a particular deliverable.

 

Income Taxes

 

We provide for income taxes by taking into account the differences between the financial statement treatment and tax treatment of certain transactions. Deferred tax assets and liabilities are recognized for the anticipated 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. This calculation requires us to make certain estimates about our future operations, and many of these estimates of future operations may be imprecise. Changes in state, federal, and foreign tax laws, as well as changes in our financial condition, could affect these estimates. In addition, we consider many factors when evaluating and estimating income tax uncertainties. These factors include an evaluation of the technical merits of the tax position as well as the amounts and probabilities of the outcomes that could be realized upon ultimate settlement. The actual resolution of those uncertainties will inevitably differ from those estimates, and such differences may be material to the financial statements. Our estimates and judgments associated with our calculations of income taxes have been reasonable in the past, however, the possibility for changes in the tax laws, as well as the current economic uncertainty, could affect the accuracy of our income tax estimates in future periods.

 

Acquisition Purchase Price Allocations

 

We account for acquisitions of businesses using the purchase method, which requires the allocation of the purchase price based on the fair values of the assets and liabilities acquired. We estimate the fair values of the assets and liabilities acquired using accepted valuation methods, and, in many cases, such estimates are based on our judgments as to the future operating cash flows expected to be generated from the acquired assets throughout their estimated useful lives. We have completed several acquisitions during the past several years and have accounted for the various assets (including intangible assets) and liabilities acquired based on our estimate of fair values. Goodwill represents the excess of acquisition purchase price over the estimated fair values of the net assets acquired. Our estimates and judgments of the fair value of acquired businesses are imprecise, and the use of inaccurate fair value estimates could result in the improper allocation of the acquisition purchase price to acquired assets and liabilities, which could result in asset impairments, the recording of previously unrecorded liabilities, and other financial statement adjustments. The difficulty in estimating the fair values of acquired assets and liabilities is increased during periods of economic uncertainty.

 

34

 

Results of Operations

 

The following data should be read in conjunction with the Consolidated Financial Statements and the associated Notes contained elsewhere in this report.

 

201 2 Compared to 201 1

 

Consolidated Comparisons

 

Year Ended

 

 

 

December 31,

 

Period to Period Change

 

2012

 

2011

 

2012 vs 2011

 

% Change

 

(In Thousands, Except Percentages)

Revenues

$

880,831  

 

 

$

845,275  

 

 

$

35,556  

 

 

 

4.2%  

 

Gross profit

 

168,869  

 

 

 

90,510  

 

 

 

78,359  

 

 

 

86.6%  

 

Gross profit as a percentage of revenue

 

19.2%  

 

 

 

10.7%  

 

 

 

 

 

 

 

 

 

General and administrative expense

 

133,138  

 

 

 

113,273  

 

 

 

19,865  

 

 

 

17.5%  

 

General and administrative expense as a

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

percentage of revenue

 

15.1%  

 

 

 

13.4%  

 

 

 

 

 

 

 

 

 

Interest expense, net

 

17,080  

 

 

 

16,439  

 

 

 

641  

 

 

 

3.9%  

 

(Gain) loss on sale of assets

 

(4,916)

 

 

 

(58,674)

 

 

 

53,758  

 

 

 

 

 

Other (income) expense, net

 

(4,616)

 

 

 

13,239  

 

 

 

(17,855)

 

 

 

 

 

Income before taxes and discontinued operations

 

28,183  

 

 

 

6,233  

 

 

 

21,950  

 

 

 

352.2%  

 

Income before taxes and discontinued

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

operations as a percentage of revenue

 

3.2%  

 

 

 

0.7%  

 

 

 

 

 

 

 

 

 

Provision for income taxes

 

9,429  

 

 

 

751  

 

 

 

8,678  

 

 

 

1155.5%  

 

Income before discontinued operations

 

18,754  

 

 

 

5,482  

 

 

 

13,272  

 

 

 

242.1%  

 

Income (loss) from discontinued operations,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

net of taxes

 

3  

 

 

 

(64)

 

 

 

67  

 

 

 

 

 

Net income

 

18,757  

 

 

 

5,418  

 

 

 

13,339  

 

 

 

246.2%  

 

Net income attributable to noncontrolling interest

 

(2,797)

 

 

 

(1,271)

 

 

 

(1,526)

 

 

 

 

 

Net income attributable to TETRA stockholders

$

15,960  

 

 

$

4,147  

 

 

$

11,813  

 

 

 

284.9%  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Consolidated revenues during 2012 in creased compared to 2011 due to the growth and increased activity for many of our businesses , including unprecedented revenue levels for our Fluids, Production Testing, and Compressco segments . In partic ular, the acquisitions of OPTIMA , ERS, and Greywo lf contributed $62.2 million of increased revenues for our Production Testing segment during 2012, along with $20.7 million of increased gross profit. In addition, our Production Testing segment also reported increased revenues co mpared to the prior year due to increased domestic drilling activity, particularly in certain of the shale reservoir markets it serves. Our Fluids segment’s revenue and gross profit growth was also due to increased industry activity, which resulted in increased CBF product sales, and more than offset the decreased product sales by the segment’s manufactured products businesses. Compressco also reported increased revenues and gross profit, primarily due to increased activity and demand in Latin America. These increased revenues more than offset the $76.6 million decrease in Maritech revenues due to the sale s of substantially all of its oil and gas producing properties during 2011 and ear ly 2012. In addition, Offshore Services revenues from third party customers as a result of the 2011 purchase of a heavy lift barge were largely offset by decreased diving and well abandonment services revenue, and the segment’s gross profit decreased prima rily due to decreased diving and cutting services profitability. Overall gross profit increased, however, primarily due to significant impairments and excess decommissioning costs recorded by Mari tech during the prior year , the aforementioned acquisitions, and the increased profitability of our Fluids, Production Testing, and Compressco segments during the current year .

 

Consolidated general and administrative expenses incre ased during 2012 compared to 2011 by $19.9 million , primarily due to approximately $14.8 million of increased salaries, benefits, and other employee related costs, partially due to increased headcount as a result of acquisitions as well as due to increased equity compensation. In addition, general and administrative expenses also increased due to approximately $4.5 million of increased professional fee expenses, approximately $1.3 million of increased office expenses, and approximately $0.3 million of increased insurance and taxes expense. These increases in consolidated general and administrative expenses were partially offset by a decrease of approximately $1.0 million of other general expenses, including decreased provision for doubtful accounts. The increased professiona l fee expenses included approximately $2.8 million o f acquisition transaction costs.

 

35

 

Consolidated net in terest expense increased by $0.6 million compared to the prior year. This increase is due to increased borrowings during 2012.

 

D uring 2011, Maritech recorded gains on sales of its oil and gas properties, including approximately $58.2 million from a sale of approximately 79% of its oil and gas producing properties during the second quarter of 2011. Gains on sales of assets during 20 12 consist primarily of the $5.6 million of gain s recorded by our Offshore Services segment for the sale of our electric wireline assets during the fourth quarter of 2012 and the sal e of certain abandonment assets during the first quarter of 2012. Consolidated other income increased during 2012 compared to the prior year, primarily due to $14.2 million of hedge ineffectiveness losses recorded during the prior year . Consolidated other income also includes increased earnings from an unconsolidated joint venture c ompared to the prior year .

 

Our provision for income taxes in creased during 2012 co mpared to 2011 due to in creased net earn ings for the current year .

 

Divisional Comparisons

 

Fluids Division

 

Year Ended

 

 

 

December 31,

 

Period to Period Change

 

2012

 

2011

 

2012 vs 2011

 

% Change

 

(In Thousands, Except Percentages)

Revenues

$

334,548  

 

 

$

304,536  

 

 

$

30,012  

 

 

 

9.9%  

 

Gross profit

 

79,454  

 

 

 

57,470  

 

 

 

21,984  

 

 

 

38.3%  

 

Gross profit as a percentage of revenue

 

23.7%  

 

 

 

18.9%  

 

 

 

 

 

 

 

 

 

General and administrative expense

 

30,466  

 

 

 

26,586  

 

 

 

3,880  

 

 

 

14.6%  

 

General and administrative expense as a

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

percentage of revenue

 

9.1%  

 

 

 

8.7%  

 

 

 

 

 

 

 

 

 

Interest (income) expense, net

 

54  

 

 

 

14  

 

 

 

40  

 

 

 

 

 

Other (income) expense, net

 

(1,896)

 

 

 

(1,206)

 

 

 

(690)

 

 

 

 

 

Income before taxes and discontinued operations

$

50,830  

 

 

$

32,076  

 

 

$

18,754  

 

 

 

58.5%  

 

Income before taxes and discontinued

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

operations as a percentage of revenue

 

15.2%  

 

 

 

10.5%  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The increase in Fluids Division revenues during 2012 compared to 2011 was primarily due to a $28.1 million net increase in product sales revenues. This increas e was due to approximately $40.7 million of increased clear brine fluids (CBFs) product sales revenues , primarily due to increased domestic offshore well completion activity. This increase in domestic demand is due to increased activity in the deepwater Gulf of Mexico, as activity levels in late 2012 have returned to the pre-Macondo levels of early 2010. In addition, increased activity in our Eastern Hemisphere markets have also contributed, particularly in the North Sea, West Africa, and the Middle East regions. We expect these increased activity levels to continue in 2013. The increase in CBF sales was parti ally offset by approximately $12.5 million of decreased revenue from manufactured products, primarily from decreased industrial demand due to weather , increased competition, and due to the reduced sales of dry calcium chlori de following the shutdown of the pellet plant at our Lake Charles facility during mid-2011. In addition to the net increase in product sales reven ues, the Division also reported a $1.8 million increase in services revenues due to in creased domestic frac water management service activity in certain of the Division’s shale reservoir markets compared to the prior year . However, the growth in domestic onshore service revenues has slowed compared to prior year periods.

 

Fluids Division gross profit increased compared to 2011 primarily as a result of the increased domestic CBF revenues discussed above and from increased efficiency at our El Dorado, Arkansas, calcium chloride plant. Gross profit from the Division’s domestic onshore frac water management services operation also increased. We expect to benefit from ongoing operational improvements at our El Dorado, Arkansas, calcium chloride facility in 2013. These increases were partially offset by decreased gross profit from the Division’s European manufactured products operation, which was impacted by the decreased demand discussed above. In addition, the Division’s European calcium chloride plant experienced reduced production levels and higher costs during 2012 associated with equipment repairs at its calcium chloride plant .

 

36

 

Fluids Division income before taxes increased compared to the prior year due to the increase in gross profit discussed above and increased other income, despite increased administrative costs. Other income increased primarily due to increased income from an unconsolidated joint venture and foreign currency exchange gains. Fluids Division administrative costs increased, primarily due to increased salaries, benefits, and personnel-related costs .

 

Production Enhancement Division

 

Production Testing Segment

 

Year Ended

 

 

 

December 31,

 

Period to Period Change

 

2012

 

2011

 

2012 vs 2011

 

% Change

 

(In Thousands, Except Percentages)

Revenues

$

207,984  

 

 

$

139,756  

 

 

$

68,228  

 

 

 

48.8%  

 

Gross profit

 

58,009  

 

 

 

46,889  

 

 

 

11,120  

 

 

 

23.7%  

 

Gross profit as a percentage of revenue

 

27.9%  

 

 

 

33.6%  

 

 

 

 

 

 

 

 

 

General and administrative expense

 

23,386  

 

 

 

13,809  

 

 

 

9,577  

 

 

 

69.4%  

 

General and administrative expense as

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

a percentage of revenue

 

11.2%  

 

 

 

9.9%  

 

 

 

 

 

 

 

 

 

Interest (income) expense, net

 

(43)

 

 

 

(59)

 

 

 

16  

 

 

 

 

 

Other (income) expense, net

 

(5,181)

 

 

 

(2,830)

 

 

 

(2,351)

 

 

 

 

 

Income before taxes and discontinued operations

$

39,847  

 

 

$

35,969  

 

 

$

3,878  

 

 

 

10.8%  

 

Income before taxes and discontinued

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

operations as a percentage of revenue

 

19.2%  

 

 

 

25.7%  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production Testing revenues increased significantly during 2012 , primarily due to an increase of approximately $62.2 million resulting from the acquisitions of OPTIMA , ERS, and Greywolf during 2012. These acquisitions have resulted in the Production Testing segment increasing its scope of services and expanding its operations into strategic geographic markets. In addition, the segment reflected revenues from increased domestic drilling in many of its shale reservoir markets comp ared to the prior year. These increases, along with increased revenues from the segment’s Eastern Hemisphere operations, were partially offset by decreased revenues in Mexico, where demand for certain of the segment’s production testing services has decreased and been more than offset, on a consolidated basis, by increased demand for well monitoring services by our Compressco segment.

 

Production Testing segment gross profit increased in 2012 c ompared to 2011, pri marily due to approximately $20.7 million of increased gross profit from the acquisitions discussed above. Excluding the increased gross profit from these acquisitions, the impact from increased domestic activity was more than offset by increased operating expenses. In addition, gross profit from the segment’s international operations decreased comp ared to the prior year as a result of the decreased production testing activity in Mexico.

 

Production Testing income before taxes increased due to the increased gross profit discussed above, as well as due to increased other income, which was primarily due to increased earnings from an unconsolidated joint venture. The increases in gross profit and other income were partially offset by increased administrative expenses resulting f rom higher personnel-related costs associated with the acquisition s, as well as approximately $2.8 million of acquisition transaction costs expensed during the period .

 

37

Compressco Segment

 

Year Ended

 

 

 

December 31,

 

Period to Period Change

 

2012

 

2011

 

2012 vs 2011

 

% Change

 

(In Thousands, Except Percentages)

Revenues

$

109,466  

 

 

$

95,768  

 

 

$

13,698  

 

 

 

14.3%  

 

Gross profit

 

40,479  

 

 

 

31,035  

 

 

 

9,444  

 

 

 

30.4%  

 

Gross profit as a percentage of revenue

 

37.0%  

 

 

 

32.4%  

 

 

 

 

 

 

 

 

 

General and administrative expense

 

18,912  

 

 

 

14,320  

 

 

 

4,592  

 

 

 

32.1%  

 

General and administrative expense as

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

a percentage of revenue

 

17.3%  

 

 

 

15.0%  

 

 

 

 

 

 

 

 

 

Interest (income) expense, net

 

25  

 

 

 

(67)

 

 

 

92  

 

 

 

 

 

Other (income) expense, net

 

944  

 

 

 

983  

 

 

 

(39)

 

 

 

 

 

Income before taxes and discontinued operations

$

20,598  

 

 

$

15,799  

 

 

$

4,799  

 

 

 

30.4%  

 

Income before taxes and discontinued

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

operations as a percentage of revenue

 

18.8%  

 

 

 

16.5%  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The increase in Compressco revenues compared to the prior year period was primarily due to an increase of $ 20.6 million of service revenues resulting from increased activity, particularly in Latin America. While there are uncertainties in Latin America that could affect operations, including the renewal of certain customer contracts, we expect revenues from our Latin American operations will continue to increase. Partially offsetting this increase was a $ 6.9 million decrease from sales of compressor units and parts during 2012 compared to the prior year. Compressco continues to expand its fleet in Latin America to serve the increasing demand.

 

Compressco gross profit increased during 2012 compared to 2011 , primarily due to the increased Latin America activity discussed above, an increase in overall average compressor unit utilization from 77.4 % to 83.0 %, and also due to continuing reductions in domestic operating expenses.

 

Income before taxes for Compressco increased during 2012 compared to 2011 due to the increase d gross profit discussed above and despite increased administrative expenses. Compressco’s administrative expenses reflect increased administrative staff and professional fee expenses associated with being a separate publicly traded limited partnership. A dministrative expenses during the current year period also reflect increased equity compensation expense arising from current year equity grants by Compressco Partners and the impact of a severance agreement. Additionally, incentive compensation expense increased as a result of favorable overall financial results. B eginning in June 2011, general and administrative expense also includes the allocation of a portion of our corporate administrative expenses to Compressco Partners pursuant to our Omnibus Agreement with Compressco Partners.

 

Offshore Division

 

Offshore Services Segment

 

Year Ended

 

 

 

December 31,

 

Period to Period Change

 

2012

 

2011

 

2012 vs 2011

 

% Change

 

(In Thousands, Except Percentages)

Revenues

$

265,943  

 

 

$

287,300  

 

 

$

(21,357)

 

 

 

(7.4)%

 

Gross profit

 

33,272  

 

 

 

33,394  

 

 

 

(122)

 

 

 

(0.4)%

 

Gross profit as a percentage of revenue

 

12.5%  

 

 

 

11.6%  

 

 

 

 

 

 

 

 

 

General and administrative expense

 

17,494  

 

 

 

15,970  

 

 

 

1,524  

 

 

 

9.5%  

 

General and administrative expense as a

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

percentage of revenue

 

6.6%  

 

 

 

5.6%  

 

 

 

 

 

 

 

 

 

Interest (income) expense, net

 

109  

 

 

 

45  

 

 

 

64  

 

 

 

 

 

Other (income) expense, net

 

(6,037)

 

 

 

(1,076)

 

 

 

(4,961)

 

 

 

 

 

Income before taxes and discontinued operations

$

21,706  

 

 

$

18,455  

 

 

$

3,251  

 

 

 

17.6%  

 

Income before taxes and discontinued

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

operations as a percentage of revenue

 

8.2%  

 

 

 

6.4%  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 


Revenues from our Offshore Services segment decreased in 2012 c ompared to 2011, primarily due to a decrease in the work performed for Maritec h during the current year . Increased decommissioning services revenues, including those from the TETRA Hedron heavy lift barge purchase d during 2011, were offset by

 

38

 

decreased diving, abandonment, and cutting services revenue s during 2012 . In addition to the continuing challenges of pricing pressures, reduced activity levels, reduced number of leased vessels, and project delays experienced by several of the Offshore Services segment’s customers, the segment also experienced weather disruption s during the current year , particularly from Tropical Storm Debby and Hurricane Isaac. Diving services revenues were also negatively affected by scheduled vessel repairs during the first qu arter of 2012 . In addition, revenues decreased due to the 2011 and early 2012 sales of certain of the segment’s onshore abandonment assets and operations, which generated approximately $ 13.7 million in revenues during the prior year period. In December 2012, the segment also disposed of its wireline assets, which generated $4.0 million and $1.7 million of revenues during 2011 and 2012, respectively. Approximately $ 41.2 million of Offshore Services revenues were from work performed for Maritech during 2012, compared to $65.0 million of su ch work in the prior year . Maritech plans to continue to aggressively decommission and abandon its remaining oil and gas platform structures , and we expect that the majority of this remaining Maritech work will be completed during 2013 . I ntercompany revenues from Maritech work are eliminated in consolidation.

 

Gross profit for the Offshore Services segment during 2012 slightly decreased compared to 2011, despite approximately $ 6.2 million of due diligence and start up co sts during 2011 associated with the purchase of the TETRA Hedron. G ross profit decreased primarily due to decreased profitability of our diving and cutting services operations, which largely resulted from decreased utilization and pricin g during 2012 . In the fourth quarter of 2012, we reclassified the TETRA DB-1 derrick barge as an asset held for sale and recorded a $7.7 million impairment on the asset. The segment also identified other asset impairments of approximately $0.7 million. The decrease d profitability of our diving and cutting operations was partially offset by improved profitability of our heavy lift and abandonment operations. In addition to the impact of ongoing cost reductions that began during 2012, the Offshore Services segment expects increased profitability during 2013 as a result of increased bid activity and an observed decrease in Gulf of Mexico federal permitting delays.

 

Offshore Services segment income before taxes increased during 2012 , despite the reduced gross profit discussed above and increased general and administrative expenses . These decreases were more than offset by the gain s on the sale of certain abandonment and wireline assets that generated approximately $ 5.6 million of other income during 2012. Offshore Services segment administrative expenses increased during 2012, primarily due to increased salary and employee related expenses and increased bad debt and professional fee expenses during the year. Segment administrative expenses are expecte d to decrease going forward due to ongoing cost reductions that began in late 2012.

 

Maritech Segment

<

 

Year Ended

 

 

 

December 31,

 

Period to Period Change

 

2012

 

2011

 

2012 vs 2011

 

% Change

 

(In Thousands, Except Percentages)

Revenues

$

6,158  

 

 

$

82,740  

 

 

$

(76,582)

 

 

 

(92.6)%

 

Gross profit (loss)

 

(39,397)

 

 

 

(75,762)

 

 

 

36,365  

 

 

 

48.0%  

 

Gross profit (loss) as a percentage of revenue

 

(639.8)%

 

 

 

(91.6)%

 

 

 

 

 

 

 

 

 

General and administrative expense