TETRA TECHNOLOGIES INC
10-Ks and 10-Qs
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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,
2009
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)
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DELAWARE
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74-2148293
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(STATE OR
OTHER JURISDICTION OF
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(I.R.S.
EMPLOYER
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INCORPORATION
OR ORGANIZATION)
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IDENTIFICATION
NO.)
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24955
INTERSTATE 45 NORTH
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THE
WOODLANDS, TEXAS
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77380
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(ADDRESS OF
PRINCIPAL EXECUTIVE OFFICES)
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(ZIP
CODE)
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REGISTRANT’S
TELEPHONE NUMBER, INCLUDING AREA CODE:
(281)
367-1983
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SECURITIES
REGISTERED PURSUANT TO SECTION 12(b) OF THE
A
CT:
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COMMON STOCK,
PAR VALUE $.01 PER SHARE
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NEW YORK
STOCK EXCHANGE
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(TITLE OF
CLASS)
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(NAME OF
EXCHANGE ON WHICH REGISTERED)
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RIGHTS TO
PURCHASE SERIES ONE
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JUNIOR
PARTICIPATING PREFERRED STOCK
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NEW YORK
STOCK EXCHANGE
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(TITLE OF
CLASS)
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(NAME OF
EXCHANGE ON WHICH REGISTERED)
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S
ECURITIES REGISTERED
PURSUANT TO SECTION 12(g) OF THE ACT:
NONE
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INDICATE BY CHECK
MARK IF THE REGISTRANT IS A WELL-KNOWN SEASONED ISSUER (AS DEFINED IN RULE 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 [ ] 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 DEFINITIONS OF
“LARGE ACCELERATED FILER,” “ACCELERATED FILER,” AND “SMALLER REPORTING
COMPANY” IN RULE 12b-2 OF THE EXCHANGE ACT. (CHECK
ONE):
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LARGE
ACCELERATED FILER [ X ]
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ACCELERATED
FILER [ ]
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NON-ACCELERATED
FILER [ ]
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SMALLER
REPORTING COMPANY
[ ]
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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
$581,526,580 AS OF JUNE 30, 2009, 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, 2010 WAS 75,567,051
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 5, 2010 TO BE FILED WITH THE SECURITIES
AND EXCHANGE COMMISSION WITHIN 120 DAYS OF THE END OF THE REGISTRANT’S FISCAL
YEAR.
TABLE OF
CONTENTS
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Part
I
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Item
1.
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Business
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1 |
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Item
1A.
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Risk
Factors
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11 |
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Item
1B.
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Unresolved
Staff Comments
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24 |
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Item
2.
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Properties
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24 |
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Item
3.
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Legal
Proceedings
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28 |
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Item
4.
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[Removed and
Reserved]
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29 |
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Part
II
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Item
5.
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Market for
Registrant’s Common Equity, Related Stockholder Matters
and
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Issuer
Purchases of Equity Securities
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30 | |
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Item
6.
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Selected
Financial Data
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31 |
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Item
7.
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Management’s
Discussion and Analysis of Financial Condition
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and
Results of Operation
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32 | |
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Item
7A.
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Quantitative
and Qualitative Disclosures about Market Risk
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57 |
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Item
8.
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Financial
Statements and Supplementary Data
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59 |
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Item
9.
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Changes in
and Disagreements with Accountants on Accounting
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and
Financial Disclosure
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59 | |
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Item
9A.
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Controls and
Procedures
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59 |
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Item
9B.
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Other
Information
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60 |
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Part
III
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Item
10.
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Directors,
Executive Officers and Corporate Governance
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61 |
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Item
11.
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Executive
Compensation
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61 |
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Item
12.
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Security
Ownership of Certain Beneficial Owners and Management and
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Related
Stockholder Matters
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61 | |
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Item
13.
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Certain
Relationships and Related Transactions, and Director
Independence
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61 |
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Item
14.
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Principal
Accounting Fees and Services
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61 |
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Part
IV
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Item
15.
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Exhibits,
Financial Statement Schedules
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62 |
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, working 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.
General
We
are a geographically diversified oil and gas services company focused on
completion fluids and other products, production testing, wellhead compression,
and selected offshore services including well plugging and abandonment,
decommissioning, and diving, with a concentrated domestic exploration and
production business. We are composed of five reporting segments organized into
three divisions – Fluids, Offshore, and Production Enhancement.
Our Fluids Division
manufactures and markets clear brine fluids, additives, and other associated
products and services to the oil and gas industry for use in well drilling,
completion, and workover operations, both in the United States and in certain
regions of Latin America, Europe, Asia, and Africa. The Division also markets
liquid and dry calcium chloride manufactured at its production facilities to a
variety of markets outside the energy industry.
Our Offshore
Division consists of two operating segments: Offshore Services and Maritech, an
oil and gas exploration and production segment. The Offshore Services segment
provides (1) downhole and subsea services such as plugging and abandonment,
workover, and wireline services, (2) construction and decommissioning services,
including hurricane damage remediation, utilizing our heavy lift barges and
cutting technologies in the construction or decommissioning of offshore oil and
gas production platforms and pipelines, and (3) diving services involving
conventional and saturated air diving and the operation of several dive support
vessels.
The Maritech
segment consists of our Maritech Resources, Inc. (Maritech) subsidiary, which,
with its subsidiaries, is an oil and gas exploration and production company
focused in the offshore, inland waters, and onshore U.S. Gulf Coast region.
Maritech periodically acquires oil and gas properties in order to replenish or
expand its production operations and to provide additional development and
exploitation opportunities. The Offshore Division’s Offshore Services segment
performs a significant portion of the well abandonment and decommissioning
services required by Maritech.
Our Production
Enhancement Division consists of two operating segments: Production Testing and
Compressco. The Production Testing segment provides production testing services
in many of the major oil and gas basins in the United States, as well as onshore
basins in Mexico, Brazil, Northern Africa, the Middle East, and other
international markets.
The Compressco
segment provides wellhead compression-based production enhancement services
throughout many of the onshore producing regions of the United States, as well
as basins in Canada, Mexico, South America, Europe, Asia, and other
international locations. These compression services can improve the value of
natural gas and oil wells by increasing daily production and total recoverable
reserves.
We continue to pursue a growth strategy that
includes expanding our existing businesses – both through internal growth and
through the pursuit of suitable acquisitions – and by identifying opportunities
to establish operations in additional U.S. and international niche oil service
markets. 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.
1
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, free of charge, on our website, 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, sodium bromide, calcium bromide, zinc bromide, and similar products
produced by our Fluids Division are referred to as clear brine fluids (CBFs) in
the oil and gas industry. CBFs are typically solids-free, clear salt solutions
that have variable densities and are used as weighting fluids to control
bottomhole pressures during oil and gas completion and workover activities. The
use of CBFs can contribute to increased production by reducing the likelihood of
damage to the wellbore and productive pay zone. CBFs are particularly important
in offshore completion and workover operations due to the potentially greater
formation sensitivity, the significantly greater investment necessary to drill
and produce offshore, and the consequent higher cost of error. CBFs are
manufactured and distributed by our Fluids Division and are also sold to other
companies that service customers in the oil and gas industry.
Our Fluids Division
provides basic and custom blended CBFs to U.S. and international oil and gas
well operators based on the specific need of the customer and the proposed
application of the product. We also provide these customers with a broad range
of associated services, including onsite fluid filtration, handling, and
recycling; wellbore cleanup; fluid engineering consultation; and fluid
management, including high volume water transfer services in support of high
pressure fracturing processes. We also offer to repurchase (buyback) used CBFs
from customers, which we then recondition and recycle. The utilization of
reconditioned CBFs reduces the net cost of the CBFs to our customers and
minimizes the need to dispose of used fluids. We recondition the CBFs through
filtration, blending, and the use of proprietary chemical processes, and then
market the reconditioned CBFs.
The Division’s
fluid engineering and management personnel use proprietary technology to
determine the optimal CBF blend for a customer’s particular application to
maximize the effectiveness and lifespan of the CBFs. We modify the specific
volume, density, crystallization temperature, and chemical composition of the
CBFs to satisfy a customer’s specific requirements. Our filtration services use
a variety of techniques and equipment for the onsite removal of particulates
from CBFs, so that those CBFs can be recirculated back into the well. Filtration
also enables recovery of a greater percentage of used CBFs for
recycling.
The Fluids Division
produces CBFs from its production facilities that manufacture liquid and dry
calcium chloride, sodium bromide, calcium bromide, zinc bromide and zinc calcium
bromide for distribution into energy markets. Liquid and dry calcium chloride
are also sold into the water treatment, industrial, cement, food processing,
dust control, 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.
We
manufacture liquid and dry calcium chloride in production facilities located in
the United States and Europe. We also acquire raw material and production from
other sources, including non-owned plants under agreements with the owners.
During the fourth quarter of 2009, we began production of liquid calcium
chloride at our newly completed plant near El Dorado, Arkansas. This plant also
began production of dry (flake) calcium chloride during January 2010. Dry
calcium chloride is also produced at our Kokkola, Finland
2
plant. We operate
our European calcium chloride manufacturing operations under the name TETRA
Chemicals Europe. We also operate a plant in Lake Charles, Louisiana, where we
produce mainly dry calcium chloride. We manufacture liquid calcium chloride from
our facility in Parkersburg, West Virginia and have two solar evaporation plants
located in San Bernardino County, California, which produce liquid calcium
chloride from underground brine reserves. These plant facilities have a combined
production capacity of more than 1.5 million tons per year.
We
manufacture and distribute sodium bromide, calcium bromide and zinc bromide from
our West Memphis, Arkansas, facility. A patented and proprietary production
process utilized at this facility uses bromine or hydrobromic acid, along with
various zinc sources, to manufacture these products. The group purchases raw
material bromine pursuant to a long-term supply agreement. This facility also
uses patented and proprietary technologies to recondition and upgrade used CBFs
repurchased from our customers. In addition, our El Dorado, Arkansas, plant
facility produces magnesium hydroxide as a by-product, and, beginning in 2011,
will be capable of sodium chloride (salt) production.
We
also have approximately 33,000 gross acres of bromine-containing brine reserves
in Magnolia, Arkansas, that are under lease. We hold these assets for possible
future development.
See “Note Q – Industry Segments and Geographic
Information” in the Notes to Consolidated Financial Statements for financial
information about this Division.
Offshore
Division
Our Offshore
Division consists of two separate operating segments: the Offshore Services and
Maritech segments. The Offshore Services segment provides (1) downhole and
subsea services such as plugging and abandonment (P&A), workover, and
wireline services, (2) construction and decommissioning services, including
hurricane damage remediation, utilizing our heavy lift barges and cutting
technologies in the construction or decommissioning of offshore oil and gas
production platforms, subsea wells, and pipelines, and (3) diving services
involving conventional and saturated air diving and the operation of several
dive support vessels. While we are a leading provider of these services to the
offshore Gulf of Mexico well abandonment and decommissioning markets, we provide
these services to other oilfield markets as well, including the inland water and
onshore markets in the Gulf of Mexico region. We offer comprehensive, integrated
solutions to our customers, including engineering consultation and project
management services. We provide individualized services to meet our customers’
specific requirements. The Maritech segment is an oil and gas exploration and
production company focused in the offshore, inland waters, and onshore regions
of the U.S. Gulf of Mexico. Maritech periodically acquires oil and gas
properties in order to replenish or expand its production and to provide
additional development and exploitation opportunities. The Offshore Division’s
Offshore Services segment performs a significant portion of the well abandonment
and decommissioning services required by Maritech, and Maritech is a significant
customer of the Offshore Services segment.
In providing its array of services, our
Offshore Services segment utilizes barge-mounted rigs, a platform rig, offshore
rigless P&A packages, two heavy lift vessels, several dive support vessels
and other dive support assets and onshore rigs which we own and operate. In
addition, we rent certain equipment from third party contractors whenever
necessary. The Division provides a wide variety of contract diving services to
its customers through our subsidiary, Epic Diving & Marine Services (Epic).
Construction, well abandonment, and decommissioning services are performed
primarily offshore in the Gulf of Mexico, although the Division also provides
well abandonment services to customers in the inland waters and onshore in Texas
and Louisiana. The Division also provides onshore and offshore cutting services
and tool rentals through its E.O.T. Rentals (EOT) operations. The Division’s
electric wireline operations specializes in cased-hole logging, mechanical
completion services, plugbacks, bridge plugs and packer services, pipe recovery
(cased and open hole), perforating, and tubing-conveyed perforating services.
The Offshore Services segment has been successful in marketing its experience,
utilizing the specialized equipment and engineering expertise necessary to
address a variety of specific construction and platform decommissioning issues,
including project management and the issues associated with platforms toppled or
severely damaged by hurricanes in the Gulf of Mexico. The Division provides
services to major oil and gas companies and independent operators, including
Maritech, through its facilities located in Lafayette, Broussard, Harvey, and
Houma, Louisiana and in Bryan and Victoria, Texas.
3
The size of our
Offshore Division’s fleet of service vessels has been adjusted in recent years
to serve the changing demand for well abandonment, construction, platform
decommissioning, diving, and other offshore services. We currently have two
vessels with the capacity to perform heavy lift projects and integrated
operations on oil and gas production platforms. Subsequent to our acquisition of
Epic in March 2006, we purchased a dynamically positioned dive support vessel,
which we renamed the Epic Diver, and refurbished two of Epic’s existing dive
support vessels, the Epic Explorer and the Epic Seahorse. Both the Epic Diver
and the Epic Explorer offer saturation diving systems that are rated for up to
1,000 foot dive depths. Beginning in June 2009, we increased our service fleet
through the leasing of a specialized dive service vessel which is being utilized
for hurricane recovery work.
Maritech acquires,
manages, explores, and develops oil and gas properties in the offshore, inland
water, and onshore U.S. Gulf Coast region. Maritech periodically acquires oil
and gas properties in order to replenish or expand its production and to provide
additional development and exploitation opportunities. The Offshore Division’s
Offshore Services segment performs a significant portion of the well abandonment
and decommissioning services required by Maritech. Federal regulations generally
require lessees to plug and abandon wells and decommission the associated
platforms, pipelines, and other equipment within one year after the lease
terminates.
Maritech grows its
operations by acquiring and developing oil and gas property interests located in
the offshore, inland waters, and onshore U.S. Gulf of Mexico region. Maritech
acquires both producing oil and gas properties as well as prospect acreage, and
performs development and exploitation efforts in order to increase its oil and
gas reserves and replace depleting production. During 2009, Maritech
participated in drilling three wells, one each in Galveston Island 321, Main
Pass 279, and Timbalier Bay fields. All three wells were successful with an
average net finding cost of $12.90 per equivalent barrel (BOE). Maritech also
participated in numerous successful recompletions in Timbalier Bay, Lake
Hermitage, and the West Delta area. Maritech’s most significant development
efforts currently consist of East Cameron 328, the Dromedary prospect acreage
located onshore Louisiana, and the Timbalier Bay field located in the inland
waters area of Louisiana. The most recent acquisitions of producing oil and gas
properties were in December 2007 and January 2008, when Maritech purchased oil
and gas producing properties for an aggregate of $74.9 million of cash and the
assumption of associated decommissioning liabilities having an undiscounted
value of approximately $51.5 million. In December 2007, we acquired interests in
certain offshore properties located primarily in the Main Pass area of the Gulf
of Mexico from a subsidiary of Cimarex Energy (the Cimarex Properties). Maritech
completed a new condensate pipeline in April 2008, which eliminated the barging
of produced condensate from the Cimarex Properties, resulting in significantly
increased production in an area from which production had previously been
restricted. Since acquiring the Cimarex Properties, Maritech has completed the
hookup and has begun production from additional subsea wells in the Main Pass
area. In January 2008, we acquired certain offshore oil and gas producing
properties from Stone Energy Corporation. During the three year period ended
December 31, 2009, Maritech has invested significantly in its acquisition and
exploitation activities, spending approximately $290.2 million on such projects,
although such activities decreased during 2009 due to capital spending
constraints. Maritech’s activities also include the plugging, abandonment, and
decommissioning efforts on its offshore oil and gas properties, particularly as
part of its strategy to reduce its risk from future storms and in response to
the increasing cost of windstorm insurance coverage. During the three year
period ended December 31, 2009, Maritech has expended approximately $131.8
million on such efforts. As of December 31, 2009, Maritech had proved reserves
of approximately 7.1 million barrels of oil and 33.5 billion cubic feet of
natural gas, with undiscounted future net pretax cash flow of approximately
$109.4 million.
See “Note Q –
Industry Segments and Geographic Information” in the Notes to Consolidated
Financial Statements for financial information about this Division.
Production
Enhancement Division
The Production
Testing segment of the Production Enhancement Division provides flow back
pressure and volume testing of onshore and offshore oil and gas wells, providing
reservoir data necessary to enable operators to optimize production and minimize
oil and gas reservoir damage. In addition, the Production Testing segment
provides services for coiled tubing, pipeline cleanout, blowout prevention, well
cleanup, and laboratory analysis. The Production Testing segment also provides
early-life production solutions designed to access newly available production
and late-life production enhancement solutions designed to boost and extend the
productive life of oil and gas wells. Many of these services involve
4
sophisticated
evaluation techniques needed for reservoir management 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 specifically
designed to work in environments in which high levels of hydrogen sulfide gas
are present. The Production Testing segment has operating locations in each of
the operating areas in which it serves, including Louisiana, Oklahoma,
Pennsylvania, and throughout Texas. Internationally, the segment has several
locations in Mexico and South America, North Africa, Middle East, Asia, and
Europe.
During 2009, the
Production Enhancement Division entered into a technical management contract to
perform engineering, procurement, and installation of equipment needed for the
cleanup and removal of oil bearing materials at two South American refinery
locations. The contract is expected to be performed in project stages over the
next one to three year period.
The Division’s
Compressco segment is a leading provider of wellhead compression-based
production enhancement services to a broad base of natural gas and oil
exploration and production companies. These production enhancement services
include compression, liquids separation, gas metering services, and ongoing well
evaluations. Although Compressco’s services are applied primarily to mature
wells with low formation pressures, the services are also employed on newer
wells that have experienced significant production declines or that are
characterized by lower formation pressures. Compressco designs and manufactures
the compressor equipment (GasJack
®
units) it uses to provide production enhancement services. Compressco’s fleet of
GasJack
®
units
totaled 3,627 as of December 31, 2009, of which 2,660 units were in service,
representing a decrease in the number of units in service of approximately 13%
from the prior year.
Compressco’s
GasJack
®
unit
increases gas production by reducing surface pressure to allow wellbore liquids
that would normally block gas flow to produce up the well. The fluids are
separated from the gas and liquid-free gas flows into the GasJack
®
unit,
where the gas is compressed. The 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, while the other cylinders provide compression. This configuration is
capable of creating suction conditions that range from 12 in/hg (inches of
mercury) of negative pressure to 60 PSIG (Pounds per Square Inch Gauge) of
positive pressure and discharge pressures of up to 450 PSIG. Compressco utilizes
its GasJack
®
units
in conjunction with its personnel to provide compression services to its
customers, primarily on a month-to-month basis. Compressco services its
compressors and provides maintenance service on sold units through a staff of
mobile field technicians who are based throughout Compressco’s market areas. To
a lesser extent, Compressco also sells GasJack
®
units
to customers.
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, sodium bromide, calcium bromide, zinc bromide,
magnesium hydroxide, and zinc calcium bromide for distribution to its customers.
The Division also recycles calcium and zinc bromide CBFs repurchased from its
oil and gas customers.
The Division
manufactures liquid calcium chloride from a reaction of hydrochloric acid and
limestone and from natural underground brine reserves. The Division also
purchases liquid and dry calcium chloride from a number of U.S. and
international chemical manufacturers. Some of the Division’s primary sources of
hydrochloric acid are chemical co-product streams obtained from chemical
manufacturers. We have written agreements with certain of those chemical
companies regarding the supply of hydrochloric acid, bromine, or calcium
chloride. We significantly increased our production capacity following the
construction of our El Dorado, Arkansas, calcium chloride plant facility, which
finished testing in September 2009 and began production of liquid calcium
chloride during the fourth quarter of 2009. This plant is located on land
purchased from Chemtura Corporation (Chemtura) and adjacent to Chemtura’s
central bromine plant, located near El Dorado, Arkansas. This new plant is
designed to produce liquid and flake calcium chloride, along with other
co-products such as magnesium hydroxide and sodium chloride, and will allow the
Division to reduce its
5
dependence on
third-party hydrochloric acid suppliers. The plant is designed to utilize
calcium chloride containing brines (tail brine) obtained from Chemtura’s
operations. We purchase raw materials utilized by our Lake Charles facility to
produce liquid and dry (pellet) calcium chloride from a variety of sources. We
also produce calcium chloride at our two plants in San Bernardino County,
California, through evaporation of naturally occurring underground brine
reserves. These underground brine reserves are deemed adequate to supply our
foreseeable need for calcium chloride in that market area. Substantial
quantities of limestone are also consumed when converting hydrochloric acid into
calcium chloride. We use a proprietary process that permits the use of less
expensive limestone, while maintaining end-use product quality. We purchase
limestone from several different sources. Currently, hydrochloric acid and
limestone are generally available from multiple sources.
To
produce calcium bromide, zinc bromide, and zinc calcium bromide at our West
Memphis, Arkansas, facility, we use primarily bromine and various sources of
zinc raw materials and lime. We use proprietary and patented processes that
permit the use of cost-advantaged raw materials, while maintaining high product
quality. There are multiple sources of zinc that we can use in the production of
zinc bromide. In December 2006, we entered into a long-term supply agreement
with Chemtura, whereby the Division purchases its requirements of raw material
bromine from Chemtura’s Arkansas bromine facilities. In addition, Chemtura
supplies the Division’s new El Dorado calcium chloride plant with tail brine
from its Arkansas facilities following bromine extraction. During March 2009,
Chemtura announced that it had filed voluntary petitions for reorganization
under Chapter 11 of the U.S. Bankruptcy code. Under bankruptcy, Chemtura had the
right to accept or reject executory contracts, such as our agreements with them
under which we acquire bromine and brine. During the fourth quarter of 2009, we
negotiated certain amendments to our existing agreements with Chemtura, as well
as certain other agreements, and such amended agreements were approved by the
bankruptcy court. While the amended agreements do include an increase in the
cost of raw material bromine from Chemtura, other amendments to the agreements
partially mitigate the impact of the increased costs.
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 have approximately 33,000 gross acres of bromine-containing brine
reserves under lease 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. We believe we have sufficient brine reserves under
lease to operate a world-scale bromine facility for 25 to 30 years. Development
of the brine field, construction of necessary pipelines, and reconfiguration of
the plant would require a substantial capital investment. The execution of the
Chemtura bromine supply agreement discussed above provides us with an immediate
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 the
development of the Magnolia, Arkansas, assets.
Our Production
Enhancement Division, through its Production Testing segment, outsources the
construction of production testing equipment to third-party manufacturers. This
equipment is used to provide the flow back pressure and volume testing services
to the segment’s customers. The Compressco segment designs and assembles its
GasJack
®
units
which it uses to provide wellhead compression-based production enhancement
services. Some of the components used in the GasJack
®
units
are obtained from a single supplier or a limited group of suppliers. Compressco
does not have long-term contracts with these suppliers. While a partial or
complete loss of certain of these suppliers could have a negative impact on
Compressco’s business, Compressco believes that there are adequate, alternative
suppliers of these components and that this impact would not be
severe.
Market
Overview and Competition
Fluids
Division
Our Fluids Division
sells CBFs, drilling and completion fluid systems, additives, and related
products and services to oil and gas exploration and production companies,
onshore and offshore, in the United States and worldwide. Current areas of
market presence include the U.S. onshore Gulf Coast, the U.S. Gulf of Mexico,
the North Sea, Mexico, South America, Europe, Asia, and Africa. The Division is
also capitalizing on the current trend toward deepwater operations which utilize
a larger volume of CBFs and are subject to harsh downhole conditions such as
high pressure and high temperatures. In June 2008, we announced that we had
6
signed a contract
with Petroleo Brasileiro S.A. (Petrobras), the national oil company of Brazil,
to provide completion fluids and associated services on deepwater wells offshore
Brazil. Although much of Petrobras’ activity associated with this contract was
deferred during 2009, we anticipate that activity in Brazil will be increasing
beginning in 2010.
The Division’s
principal competitors in the sale of CBFs to the oil and gas industry are Baroid
Corporation, a subsidiary of Halliburton Company; M-I L.L.C., a joint venture
between Smith International, Inc. and Schlumberger Limited; and BJ Services
Company, which has announced that it is being acquired by Baker Hughes. This
market is highly competitive, and competition is based primarily on service,
availability, and price. Although all competitors provide fluid handling,
filtration, and recycling services, we believe that our historical focus on
providing these and other value-added services to our customers have enabled us
to compete successfully. Major customers of the Fluids Division include
Anadarko, Chevron, Devon, Dominion Resources, EOG Resources, Halliburton
Company, LLOG Exploration, Newfield Exploration Company, Nippon Oil Exploration,
and Shell Oil. The Division also sells its products through various distributors
worldwide.
Our liquid and dry
calcium chloride products have a wide range of uses outside the energy industry.
The non-energy market segments to which our products are marketed include
agricultural, industrial, roadway dust control and de-icing, mining, janitorial,
construction, pharmaceutical, and food processing. These products promote snow
and ice melt, dust control, cement curing, food processing, dehumidification,
and road stabilization and are also used as a source of calcium nutrients to
improve agricultural yields. We also sell sodium bromide into the industrial
water treatment markets as a biocide under the BioRid
®
trade
name. Most of these markets are highly competitive. The Division’s European
calcium chloride manufacturing operations based in Kokkola, Finland, permit us
to market our calcium chloride products to certain European markets. Our major
competitors in the calcium chloride market include Occidental Chemical
Corporation and Industrial del Alkali in North America, and Brunner Mond,
Solvay, and NedMag in Europe.
Offshore
Division
Our Offshore
Division consists of our Offshore Services and Maritech segments. The Division’s
Offshore Services operations provide downhole and subsea services such as well
abandonment, contract diving, construction, cutting, and decommissioning
services offshore, primarily in the U.S. Gulf of Mexico. In addition, the
Division also provides well abandonment, workover, and wireline services in the
onshore and inland water areas of the U.S. Gulf Coast regions of Texas and
Louisiana. Long-term demand for the Offshore Division’s offshore well
abandonment and decommissioning services is predominantly driven by the maturity
and decline of producing fields in the Gulf of Mexico, aging offshore platform
infrastructure, damage from storms, and government regulations. Demand for the
Offshore Division’s construction and other services is driven by the general
level of activity of its customers, which are also affected by oil and natural
gas prices and the general economic condition of the industry. In the market
areas in which we currently operate, regulations generally require wells to be
plugged, offshore platforms decommissioned, pipelines abandoned, and the well
site cleared within twelve months after an oil or gas lease expires. The
maturity and production decline of Gulf of Mexico oil and gas fields has, over
time, caused an increase in the number of wells to be plugged and abandoned and
platforms and pipelines to be decommissioned. Current and projected demand for
offshore abandonment and decommissioning services increased substantially as a
result of 2005 and 2008 hurricane activity in the Gulf of Mexico, which
destroyed or caused significant damage to a large number of offshore platforms
and associated wells. The Division has developed specialized equipment and
engineering expertise to provide such services to customers whose offshore wells
and production platforms were toppled, destroyed, or heavily damaged by such
storms. The threat of future storm activity, combined with increases in
hurricane insurance premiums and deductibles, has also accelerated the
abandonment and decommissioning plans for undamaged wells and structures of many
offshore operators. Offshore activities in the Gulf of Mexico have historically
been 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 participate in the current market include, among other
factors: having an adequate fleet of the proper equipment to meet current market
demand and conditions; having qualified, experienced personnel; having technical
expertise to address varying downhole, surface, and subsea conditions,
particularly those related to damaged wells and platforms; having the financial
strength to ensure all abandonment and decommissioning obligations are
satisfied; and having a comprehensive safety and environmental program. We
believe our integrated service package and vessel fleet satisfy these market
requirements, allowing us to successfully compete.
7
The Division
markets its services primarily to major oil and gas companies and independent
operators. Major customers include Apache, Chevron, Mariner Energy, Nexen
Petroleum USA Inc., Shell Oil, Stone Energy, and W&T Offshore. These
services are performed primarily offshore in the U.S. Gulf of Mexico and in the
Gulf Coast inland waters and onshore in Texas and Louisiana. Our principal
competitors in the offshore and inland water markets are Global Industries,
Ltd., Offshore Specialty Fabricators, Inc., Helix Energy Solutions,
Cal Dive International,
Inc., and Superior Energy Services, Inc. This market is highly competitive, and
competition is based primarily on service, equipment availability, safety
record, and price. Our ability to successfully bid our services can fluctuate
from year to year, depending on market conditions.
The Division’s
Maritech operation competes with a wide number of independent Gulf of Mexico
operators for the acquisition and leasing of oil and gas properties. Maritech
typically acquires oil and gas properties from major oil and gas companies as
well as from independent operators. Our ability to acquire producing oil and gas
properties under acceptable terms is dependent on numerous factors, including
oil and natural gas commodity prices, the availability of suitable properties
for acquisition, the age and condition of offshore production platforms, and the
level of competition from other operators pursuing such properties. Maritech
sells its oil and gas production to a variety of purchasers. We believe that
Maritech’s access to its affiliated Offshore Services segment allows it to
better assess and evaluate the abandonment and decommissioning obligations
associated with acquired properties. This access gives Maritech an advantage
over many other operators with which it competes for property
acquisitions.
Production
Enhancement Division
The Production
Enhancement Division, through its Production Testing and Compressco segments,
provides production testing and wellhead compression-based services and products
to its customers. The Production Testing segment provides services primarily to
the natural gas segment of the oil and gas industry. 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 reservoirs containing high levels of hydrogen sulfide gas. The
Division provides the specialized equipment and qualified personnel to address
these impediments to production and to pressure test wells and wellhead
equipment. The Production Testing segment also provides a variety of reservoir
management and laboratory testing services for oil and gas producing properties,
including coiled tubing, pipeline cleanout, blowout prevention, well cleanup,
distillation analysis, gas composition analysis, and oilfield water analysis
services. The Production Testing segment also provides early-life and late-life
production enhancement solutions designed to boost and extend the productive
life of oil and gas wells, working with our Compressco segment.
The production
testing market is 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 our equipment, skilled personnel, operating
procedures, and safety record give us a competitive advantage in the
marketplace. The Production Testing segment is also committed to growing its
international operations in order to serve most major oil and gas markets
worldwide. Competition in onshore U.S. markets is primarily dominated by
numerous small, privately-owned operators. Schlumberger Limited, Weatherford
International Oilfield Services, Halliburton, and Expro International are major
competitors in the U.S. offshore market and international markets. Our customers
include Chesapeake, ConocoPhillips, El Paso Corporation, Encana Oil & Gas,
Quicksilver Resources, Shell Oil, PEMEX (the national oil company of Mexico),
Petrobras (the national oil company of Brazil), Saudi ARAMCO (the national oil
company of Saudi Arabia), and other national oil companies in foreign
countries.
The Division’s
Compressco segment provides production enhancement services to over 400 natural
gas and oil producers throughout most of the onshore producing regions of the
United States, as well as basins in Canada, Mexico, South America, Europe, Asia,
and other international locations. Most of Compressco’s services are performed
in the Ark-La-Tex Basin, San Juan Basin, and Mid-Continent region of the United
States. While Compressco has historically targeted natural gas wells in its
operating regions that produce between 30 thousand and 300 thousand cubic feet
of natural gas per day, it is also effectively enhancing production in certain
basins with production of up to one million cubic feet of daily production.
Compressco believes that the majority of the wells it targets do not currently
utilize production enhancement services. Compressco continues to seek
opportunities to further expand its operations into other regions in the Western
Hemisphere and elsewhere in the world.
8
The wellhead
compression-based production enhancement services business is highly
competitive, and competition primarily comes from various local and regional
companies that utilize packages consisting of a screw compressor with a separate
engine driver or a reciprocating compressor with a separate engine driver. To a
lesser extent, Compressco faces competition from large national and
multinational companies that have traditionally focused on higher-horsepower
natural gas gathering and transportation equipment and services. While many of
Compressco’s competitors attempt to compete on the basis of price, Compressco
believes that its pricing is competitive because of the significant increases in
the value of natural gas wells that result from the quality of its services, its
trained field personnel, and its GasJack
®
unit
that it uses to provide the services. Compressco’s major customers include BP,
PEMEX, Devon, Chesapeake, and EXCO Resources.
Other Business
Matters
Marketing
and Distribution
The Fluids Division
markets its CBF products and services through its distribution facilities
located in the Gulf Coast region of the United States, the North Sea region of
Europe, and other selected international markets, including Brazil, West Africa,
and the Middle East. These facilities are in close proximity to both product
supplies and customer concentrations.
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 located throughout the United States and northern and central
Europe. In addition to shipping products directly from its production facilities
in the United States and Europe, the Division has distribution facilities
strategically located to provide efficient product distribution.
None of our
customers individually exceeded 10% of our total consolidated revenues during
the year ended December 31, 2009.
Backlog
The level of
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, and consists of the non-Maritech share of the well
abandonment and decommissioning work associated with the oil and gas properties
operated by Maritech. Our estimated backlog on December 31, 2009 was $121.9
million, of which approximately $7.6 million is expected to be billed during
2010. This compares to an estimated backlog of $137.8 million at December 31,
2008.
Employees
As
of December 31, 2009, we had 2,837 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 international employees are
generally members of the various labor unions and associations common to 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, 2009, we owned or licensed twenty-nine issued U.S. patents and
had six patent applications pending in the United States. Internationally, we
had fifteen owned or licensed foreign patents and one foreign patent application
pending. The foreign patents and patent applications are primarily foreign
counterparts to U.S. patents or patent applications. The issued patents expire
at various times through 2026. We have elected to maintain certain other
internally developed technologies, know-how, and inventions as trade secrets.
While we believe that the protection of our patents and trade secrets is
important to our competitive positions in our businesses, we do not believe any
one patent or trade secret is essential to our success.
9
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. 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. Our management believes, however, that it would require a substantial
period of time and substantial resources to independently develop similar
know-how or technology. As a policy, we use all possible legal means to protect
our patents, trade secrets, and other proprietary information.
We
sell various products and services under a variety of trademarks and service
marks, some of which are registered in the United States or certain foreign
countries.
Health,
Safety, and Environmental Affairs Regulations
We
are subject to various federal, state, local, and international laws and
regulations relating to occupational health and safety and the environment,
including regulations and permitting for air emissions, wastewater and
stormwater discharges, the disposal of certain hazardous and nonhazardous
wastes, and wetlands preservation. Failure to comply with these occupational
health, safety, and environmental laws and regulations or associated permits may
result in the assessment of fines and penalties and the imposition of
investigatory and remedial obligations.
With respect to our
operations in the United States, various environmental protection laws and
regulations have been enacted and amended in the U.S. during the past three
decades in response to public concerns pertaining to the environment. Our U.S.
operations and its customers are subject to these various evolving environmental
laws and corresponding regulations. In the United States, these laws and
regulations are enforced by the U.S. Environmental Protection Agency; the
Minerals Management Service of the U.S. Department of the Interior (MMS); 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. We must comply with the requirements of environmental
laws and regulations applicable to our operations, including 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 Hazardous Materials
Transportation Act of 1975; and the Pollution Prevention Act of
1990.
Our operations
outside the United States are subject to various international governmental
controls and restrictions pertaining to the environment, occupational health and
safety, and other regulated activities in the countries in which we operate. We
believe that our operations are in substantial compliance with existing
international governmental controls and regulations and that compliance with
these international controls and regulations has not had a material adverse
affect on operations.
At
our production plants, we hold various permits regulating air emissions,
wastewater and stormwater discharges, the disposal of certain hazardous and
nonhazardous wastes, and wetlands preservation.
We
believe that our manufacturing plants and other facilities are in general
compliance with all applicable 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.
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.
10
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:
|
·
|
general
economic, business, and political conditions in the markets we serve or
hope to serve in the United States and
abroad;
|
|
·
|
the supply,
demand, and prices for oil, gas, and competing energy sources, and more
particularly the supply, demand, and prices for well completion, diving,
and abandonment and decommissioning
services;
|
|
·
|
activities of
our customers and competitors;
|
|
·
|
the
availability of raw materials and labor at reasonable
prices;
|
|
·
|
operating and
safety risks inherent in oil and gas
production;
|
|
·
|
access to
pipelines, gas gathering and processing facilities for our oil and gas
production;
|
|
·
|
the potential
impact of the loss of one or more key
employees;
|
|
·
|
possible
impairments of long-lived assets, including
goodwill;
|
|
·
|
cost,
availability and adequacy of insurance and the ability to recover
thereunder;
|
|
·
|
technological
obsolescence;
|
|
·
|
weather
risks, including the risk of physical damage to our platforms, facilities
and equipment and the ability to resume operations following
damage;
|
|
·
|
our ability
to implement our business strategy;
|
|
·
|
uncertainties
about finding, developing, producing, and estimating oil and gas reserves
and plugging and abandoning wells and
structures;
|
|
·
|
the
accounting for our oil and gas operations may result in volatility of
earnings;
|
|
·
|
the
availability of capital (including any financing) to fund our business
strategy and/or operations and any restrictions resulting from such
financing;
|
|
·
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foreign
currency risks;
|
|
·
|
the impact of
existing and future laws and
regulations;
|
|
·
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environmental
risks;
|
|
·
|
estimates of
hurricane repair costs;
|
|
·
|
acquisition
valuation and integration risks;
and
|
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·
|
risks related
to our foreign operations.
|
11
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 important risk factors which 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 the general economic, financial,
business, political, and social conditions in the markets we serve or hope to
serve in the future.
The demand for our
products and services are materially dependent on the supply, demand, and prices
for oil, natural gas, and competing energy sources, and more particularly
dependent on the supply, demand, and prices for well completion, compression,
diving, and abandonment and decommissioning products and services, both in the
United States and abroad. These factors are also influenced by the regional
economic, financial, business, political, and social conditions within the
markets we serve or hope to serve, as well as the national and international
economic, financial, business, political and social conditions that impact the
supply, demand, and prices of oil and gas. Activity levels have decreased as a
result of the recent decline in energy consumption and uncertainty of the
capital markets caused by the recent global recession and financial crisis.
Decreased energy consumption has resulted in a decrease in energy prices during
much of 2009 compared to prices received during early to mid-2008. This decline
in energy prices, along with concerns regarding the availability of capital, has
negatively affected the operating cash flows and capital plans of many of our
customers, as well as our Maritech subsidiary, which has negatively impacted the
demand for many of our products and services.
If current economic
conditions continue or worsen, there may be additional constraints on oil and
gas industry spending levels for an extended period of time. Such a stagnation
of economic activity would negatively affect both the demand for many of our
products and services as well as the prices we charge for these products and
services, which would continue to negatively affect our revenues and future
growth. Many of our customers finance their drilling and production operations
through third-party lenders. The reduced availability and increased cost of
borrowing could cause our customers to reduce their spending on drilling
programs, thereby reducing demand and potentially resulting in lower pricing for
our products and services. Continued instability in the capital markets, as a
result of recession or otherwise, also may continue to affect the cost of
capital and the ability to raise capital, both for us and our
customers.
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. Current economic conditions
may be exacerbated by insufficient financial sector liquidity, leading to
additional constraints on the operating cash flows of our customers, further
limiting their activities and also potentially impacting their ability to pay us
in a timely manner, which could result in increased customer bankruptcies and
may lead to increased uncollectible receivables.
Further, an
increasing number of financial institutions and insurance companies have
reported deterioration in their financial condition. If any of our lenders,
insurers or other financial institutions are unable to fulfill their obligations
under our various credit agreements, insurance policies and other contracts, and
we are unable to find suitable replacements at a reasonable cost, our results of
operations, liquidity and cash flows could be adversely impacted.
Our oil and gas revenues and
cash flows are subject to oil and gas price volatility.
Our revenues from
oil and gas production represent approximately 19.8% of our total consolidated
revenues for the year ended December 31, 2009. Therefore, we have significant
direct market risk exposure in the pricing of our oil and gas production. Our
realized pricing is primarily driven by the prevailing worldwide price for crude
oil and spot prices in the U.S. natural gas market for our unhedged production
and the fixed prices in our derivative contracts for the portion of our oil and
gas production that is hedged. During 2009, the
12
crude oil and
natural gas prices we received averaged $61.35 and $4.00, respectively, prior to
the impact of our derivative contracts. These crude oil and natural gas prices
were significantly below the prices we received during 2008, and price
volatility for crude oil and natural gas is expected to continue. Significant
further declines in
prices for oil and natural gas could have a material adverse effect on our
results of operations and quantities of reserves recoverable on an economic
basis.
Our risk management
activities involve the use of derivative financial instruments, such as swap
agreements, to hedge the impact of market price risk exposures for a portion of
our oil and gas production. A portion of our production is sold at a fixed price
as a shield against price declines that could occur in the market. These hedging
activities limit our upside potential from oil and gas price increases, but also
limit our downside risk of decreasing oil and gas prices. In addition, we are
exposed to the volatility of oil and gas prices for the portion of our oil and
gas production that is not hedged. Currently, our derivative swap contracts do
not extend beyond December 31, 2010.
Oil and gas prices
and, therefore, the levels of well drilling, completion, workover, and
production activities, tend to fluctuate. Worldwide military, political, and
economic events, including initiatives by the Organization of Petroleum
Exporting Countries and increasing or decreasing demand in other large world
economies, 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.
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 functions of market
conditions and the product and service mix sold 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 activity levels include the finding, development, and
acquisition costs of oil and natural gas reserves; the oil and gas industry
spending levels for exploration, development, and acquisition activities;
production costs; plugging and abandonment costs; insurance costs; the success
rate of new oil and gas reserve development; and the remaining recoverable
reserves in the basins in which we operate. A large concentration of our
operating activities is located in the onshore and offshore region of the U.S.
Gulf of Mexico. Our revenues and profitability are particularly dependent upon
oil and gas industry activity and spending levels in the Gulf of Mexico region.
Our operations may also be affected by technological advances, cost of capital,
tax policies, and overall worldwide economic activity. Adverse changes in any of
these other factors may depress the levels of well drilling, completion,
workover, and production activity and result in a corresponding decline in the
demand for our products and services, thereby having a material adverse effect
on our revenues and profitability.
We encounter and expect to
continue to encounter intense competition in the sale of our products and
services.
We
compete with numerous companies in our operations. Many of our competitors have
substantially greater financial and other related resources than we have. To the
extent competitors offer comparable products or services at lower prices, or
higher quality or more cost-effective products or services, our business could
be materially and adversely affected. Certain competitors may also be better
positioned to acquire producing oil and gas properties or other businesses for
which we compete.
We are dependent upon
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, and sodium bromide, some of
which we manufacture and some of which are purchased from third parties. We also
sell calcium chloride to non-energy markets. Sales of calcium chloride and
bromide compound products contribute significantly to our revenues. In our
13
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 bromine, hydrobromic acid, and other raw materials, including various
forms of zinc, which are purchased from third parties. We rely on Chemtura as a
supplier of raw materials, both for our bromide compound products needs as well
as for the needs of our new El Dorado,
Arkansas, calcium
chloride plant. We also acquire bromide compound products from several
third-party suppliers. If we are unable to acquire the bromide compound
products, bromine, hydrobromic or hydrochloric acid, zinc, or any other supplies
of raw material at reasonable prices for a prolonged period, our business could
be materially and adversely affected.
As
a result of the current general economic conditions, many chemicals
manufacturing feedstock suppliers are experiencing reduced demand, production
interruptions, and financial difficulties. For example, during March 2009,
Chemtura announced that it had filed voluntary petitions for reorganization
under Chapter 11 of the U.S. Bankruptcy code. Under bankruptcy, Chemtura had the
right to accept or reject executory contracts, such as our agreements with them
under which we acquire bromine and brine. During the fourth quarter of 2009, we
negotiated certain amendments to our existing agreements with Chemtura, and such
amended agreements were signed by Chemtura and approved by the bankruptcy
court. While the amended agreements do include an increase in the cost of raw
material bromine from Chemtura, other amendments partially mitigate the impact
of the increased costs. Also during 2009, we wrote down the value of our
investment in a European calcium chloride manufacturing joint venture following
our joint venture partner’s announced shutdown of its adjacent plant facility
that supplies feedstock to the joint venture’s plant. In addition, occasional
supply constraints for certain of our manufacturing facilities have resulted in
certain facilities operating at less than full capacity and resulted in
decreased production volumes. A limitation of feedstock supply for our European
calcium chloride manufacturing facility affected the production levels of that
operation during a portion of 2009 and could affect its operations in the
future. The purchase of alternative supplies at a less favorable cost could also
result in decreased profitability.
Some of the well
abandonment and decommissioning services performed by our Offshore Division
require the use of vessels, equipment, and services provided by third parties.
We lease equipment and obtain services from certain providers; this equipment
and these services are subject to availability at reasonable prices, of which
there can be no assurance.
The fabrication of
GasJack
®
wellhead compressor units by our Compressco subsidiary 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. Our Compressco
operation’s profitability or future growth may be adversely affected due to our
dependence on these key suppliers.
Our exploration and
production operations are subject to the availability of drilling rigs, tubular
products, and numerous other products and services at reasonable
prices.
We may not be able to obtain
access to pipelines, gas gathering, transmission, and processing facilities to
market our oil and gas production.
The marketing of
oil and gas production depends in large part on the availability, proximity, and
capacity of pipelines, gas gathering systems and other transportation,
processing and refining facilities, as well as the existence of adequate
markets. If there was insufficient capacity available on these systems, or if
these systems were unavailable to us, the price offered for our production could
be significantly depressed, or we could be forced to shut-in some production or
delay or discontinue drilling plans while we construct our own facilities. We
also rely (and expect to rely in the future) on facilities developed and owned
by third parties in order to process, transmit, and sell our oil and gas
production. Our plans to develop and sell our oil and gas reserves could be
materially and adversely affected by the inability or unwillingness of third
parties to provide sufficient transmission or processing facilities to
us.
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
14
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 is high, and the supply is
limited. A lack of qualified personnel, therefore, could adversely affect
operating results.
The current economic
environment could result in significant impairments of certain of our long-lived
assets, including goodwill.
The current
economic environment has resulted 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 also 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. In connection with
the preparation of our annual financial statements as of December 31, 2008, we
determined that a $47.1 million impairment of goodwill was required. If current
economic and market conditions persist or decline further, we may be required to
record an additional charge to earnings during the period in which any
impairment of our goodwill is determined, resulting in an impact on our results
of operations.
Operating
Risks:
Our operations involve
significant operating risks, and insurance coverage may not be available or cost
effective.
We
are subject to operating hazards normally associated with the oilfield service
industry and offshore oil and gas production operations, 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 also include injuries to
employees and third parties during the performance of our operations. Our
operation of marine vessels, heavy equipment, offshore production platforms, and
the performance of heavy lift and diving services involve a particularly high
level 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.
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 face risks related to our
growth strategy.
Our growth strategy
includes both internal growth and growth through acquisitions. Internal growth
may require significant capital expenditure investments, some of which may
become unrecoverable or fail to
15
generate an
acceptable level of cash flows. Internal growth may also require financial
resources (including the use of available cash or additional long-term debt) and
management and personnel resources. Acquisitions also require significant
financial and 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. Any such recent or future acquisition
transactions by us may not achieve favorable financial results. Our operating
results could also be adversely affected if we are unable to successfully
integrate 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, particularly if we do not provide for economic downturns.
Future acquisitions by us could also result in issuances of equity securities,
or the rights associated with the equity securities, which could potentially
dilute earnings per share. Future acquisitions could also 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.
We have technological and
age obsolescence risk, both with our products and services as well as with our
equipment assets.
Though we believe
our products and services employ state of the art technologies and
methodologies, competitors constantly evolve their technologies and
methodologies and replace their used assets with new assets. If we are unable to
adapt to new advances 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 our heavy lift barges and dive services
vessels, are approaching the end of their useful lives and may adversely affect
our ability to serve certain customers. The replacement or upgrade of any of
these vessels will likely 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.
The production volumes and
profitability from our new El Dorado, Arkansas, calcium chloride plant facility
may not be as timely or as high as expected.
We have recently completed the construction of
a new calcium chloride plant facility near El Dorado, Arkansas. The plant’s
future profitability and the advantages we expect to receive from the plant will
be based on many factors, including the sales prices to be received for the
plant’s products, raw material and operating costs, and future demand for
products. In addition, delays in the completion of the final phases of the
calcium chloride facility, as well as changes in its operating environment,
could also affect future profitability for our Fluids Division operations
compared to original expectations.
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 turnkey, modified turnkey, or day rate 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, 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.
Oil and gas exploration and
production activities involve numerous risks and are subject to a variety of
factors that we cannot control.
We
have risks associated with our Maritech exploration and production business.
These risks include those associated with finding and developing economically
recoverable and marketable oil and natural gas
16
reserves, and
finding and acquiring leases and existing reserves on attractive terms. There
are uncertainties surrounding estimates of oil and gas reserve volumes, finding
and development costs, production costs, and abandonment and decommissioning
costs. To the extent we over-estimate future oil and natural gas sales
prices,
economically recoverable reserve volumes, or future production flow rates, or
underestimate the associated costs of exploration and production operations, our
financial results will be negatively impacted.
Drilling for oil
and natural gas is a particularly risky activity that includes the risk that we
will not encounter commercially productive oil or natural gas reservoirs. The
costs of drilling and completion operations are often difficult to estimate, and
the timing of drilling operations may be curtailed, delayed, or canceled as a
result of a variety of factors including, but not limited to:
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unexpected
drilling conditions;
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pressure or
irregularities in formations;
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equipment
failures or accidents;
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marine risks
such as capsizing, collisions, and
hurricanes;
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other adverse
weather conditions;
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shortages or
delays in the delivery of equipment;
and
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compliance
with environmental and other government requirements, which may increase
our costs or restrict our
activities.
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During the three
year period ended December 31, 2009, we have expended approximately $290.2
million of exploration and development costs, and we expect to continue to incur
significant costs in the future. During this three year period ended December
31, 2009, we charged approximately $10.8 million of dry hole costs incurred to
earnings. Future drilling activities also may not be successful, and, if
unsuccessful, this failure could have an adverse effect on our future results of
operations and financial condition. We may not recover all or any portion of our
investment in new wells. In addition, we are often uncertain as to the future
cost or timing of drilling, completing, and operating wells. While all drilling,
whether developmental or exploratory, involves these risks, exploratory drilling
involves greater risks of dry holes or failure to find commercial quantities of
hydrocarbons.
Maritech’s estimates of its
oil and gas reserves and related future cash flows are based on many factors and
assumptions, including various assumptions that are based on conditions in
existence as of the dates of the estimates. Any material changes in those
conditions, or other factors affecting those assumptions, could impair the
quantity and value of our oil and gas reserves.
Maritech’s
estimates of oil and gas reserve information are prepared in accordance with
Rule 4-10 of Regulation S-X and reflect only estimates of the accumulation of
oil and gas and the economic recoverability of those volumes. Maritech’s future
production, revenues, and expenditures with respect to such oil and gas reserves
will likely be different from estimates, and any material differences may
negatively affect our business, financial condition, and results of operations.
As a result, Maritech has experienced and may continue to experience significant
revisions to its reserve estimates.
Oil and gas
reservoir analysis is a subjective process which involves estimating underground
accumulations of oil and gas that cannot be measured in an exact manner.
Estimates of economically recoverable oil and gas reserves and of future net
cash flows associated with such reserves necessarily depend upon a number of
variable factors and assumptions. Because all reserve estimates are to some
degree subjective, each of the following items may prove to differ materially
from that assumed in estimating reserves:
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the
quantities of oil and gas that are ultimately
recovered;
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production
flow rates over time;
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the
production and operating costs
incurred;
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the amount
and timing of future development and abandonment expenditures;
and
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future oil
and gas sales prices.
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Furthermore,
different reserve engineers may make different estimates of reserves and cash
flow based on the same available data.
17
The estimated
discounted future net cash flows from proved reserves described in this Annual
Report for the year ended December 31, 2009 should not be considered as the
current market value of the estimated oil and gas proved reserves attributable
to Maritech’s properties. Such estimates are based on prices and costs in
accordance with SEC requirements, while future prices and costs may be
materially higher or lower.
Using lower prices
in forecasting reserves will result in a shorter life being given to producing
oil and natural gas properties because such properties, as their production
levels are estimated to decline, will reach an uneconomic limit with lower
prices at an earlier date. There can be no assurance that a decrease in oil and
gas prices or other differences in Maritech’s estimates of its reserves will not
adversely affect our financial position or results of operations.
The acquisition of oil and
gas properties and their associated well abandonment and decommissioning
liabilities is based on estimated data that may be materially
incorrect.
In
conjunction with our acquisition of oil and gas properties, we perform detailed
due diligence review processes that we believe are consistent with industry
practices. These acquired properties consist of both mature properties, which
are generally in the later stages of their economic lives, as well as
exploration and prospect opportunities. Each acquisition of oil and gas
properties requires a thorough review of the expected cash flows acquired and
the associated abandonment obligations assumed. The process of estimating oil
and natural gas reserves is complex, requiring significant decisions and
assumptions to be made in evaluating the available geological, geophysical,
engineering, and economic data for each reservoir. The volatility of oil and
natural gas commodity pricing additionally complicates the calculation of
estimated future cash flows of properties to be acquired. As a result, these
estimates are inherently imprecise. Actual future production, cash flows,
development expenditures, operating and abandonment expenses, and quantities of
recoverable natural gas and oil reserves may vary substantially from those
initially estimated by us. Also, in conjunction with the purchase of certain oil
and gas properties, we assume our proportionate share of the related well
abandonment and decommissioning liabilities after performing detailed estimating
procedures, analysis, and engineering studies. Our estimates of these future
well abandonment and decommissioning liabilities are imprecise and are subject
to change due to changes in the forecasts of the supply, demand, pricing 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. During 2009, Maritech adjusted its decommissioning liability,
either for work performed during the year or related to adjusted estimates of
the cost of future work to be performed. Approximately $23.8 million of this
adjustment was charged to earnings as an operating expense during 2009. 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.
Acquisitions or discoveries
of additional reserves are needed to avoid a material decline in oil and gas
reserves and production volumes.
The rate of
production from oil and gas properties generally declines as reserves are
depleted. Approximately 42.3% of our proved reserves as of December 31, 2009 are
proved producing reserves. Except to the extent that we find or acquire
additional properties containing estimated proved reserves; conduct successful
exploration or development activities; or through engineering studies, identify
additional behind-pipe zones, secondary recovery reserves, or tertiary recovery
reserves, our estimated proved reserves will decline materially as reserves are
produced. Natural gas and oil commodity pricing, as well as constraints on the
amount of capital we have available to allocate to oil and gas activities, may
limit our exploitation, development, or exploration activities for the
foreseeable future, which will reduce our ability to replace produced oil and
gas reserves. Future oil and gas production is, therefore, highly dependent upon
our ability and level of success in acquiring or finding additional
reserves.
Our accounting for oil and
gas operations may result in volatile earnings.
We
account for our oil and gas operations using the successful efforts method.
Costs incurred to drill and equip development wells, including unsuccessful
development wells, are capitalized. Costs related to unsuccessful exploratory
wells are expensed as incurred. All capitalized costs are accumulated and
recorded separately for each field and are depleted on a unit-of-production
basis, based on the estimated remaining equivalent proved oil and gas reserves
of each field. The capitalized costs of our oil and natural gas properties, on a
field basis, cannot exceed the estimated undiscounted future net cash flows of
that field. If net capitalized costs exceed undiscounted future net revenues, we
must write down the costs of each such field to our estimate of its fair market
value. Accordingly, a significant decline in oil or natural gas prices,
unsuccessful exploration and/or development efforts, or an increase in our
decommissioning liabilities could
18
cause a future
write-down of capitalized costs. During the three year period ended December 31,
2009, and primarily due to increased decommissioning liabilities and the
decrease in oil and natural gas prices, we
recorded oil and
gas property impairments on proved properties totaling approximately $130.2
million. Unproved properties are evaluated at the lower of cost or fair market
value. On a field by field basis, our oil and gas properties are assessed for
impairment in value whenever indicators become evident, with any impairment
charged to expense. Under the successful efforts method of accounting, we are
exposed to the risk that the value of a particular property (field) would have
to be written down or written off if an impairment were present.
Weather Related
Risks:
Certain of our operations,
particularly those conducted offshore, 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 turnkey and other contracts, may bear the risk of delays caused by
adverse weather conditions. Severe storms can also cause our oil and gas
producing properties to be shut-in. 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.
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 while damage
is being assessed and remediated. The costs to bring damaged offshore wells
under control and to repair or remove damaged offshore platforms and pipelines
can be significant. Moreover, even if we do not experience direct damage from
storms, we may experience disruptions in our operations because customers or
suppliers may curtail their activities due to damage to their wells, platforms,
pipelines, and other facilities.
We will expend significant
costs to repair damage as a result of 2005 and 2008 hurricanes, and a large
portion of these costs may not be covered under our insurance
policies.
We incurred significant damage to certain of
our onshore and offshore operating equipment and facilities during the third
quarters of 2005 and 2008, primarily as a result of Hurricanes Katrina, Rita,
and Ike. In particular, our Maritech subsidiary suffered varying levels of
damage to the majority of its offshore oil and gas producing platforms, and six
of its platforms were destroyed by these storms. In addition, two production
facilities located in inland waters were destroyed. Reconstruction of the two
destroyed production facilities is substantially complete, and one of the
destroyed platforms was decommissioned during 2009. A majority of our damaged
assets, with the exception of the remaining destroyed Maritech platforms, have
been repaired or are in the final stages of being repaired, and have resumed
operation. Remaining hurricane damage repair efforts consist primarily of the
well intervention, abandonment, decommissioning, and debris removal associated
with the destroyed offshore platforms and the construction of replacement
platforms and redrilling of a number of destroyed wells. While a portion of the
well intervention, abandonment, and decommissioning work has been performed on
some of the destroyed platforms and the inland water production facilities, a
significant portion of the work has yet to be performed. Through December 31,
2009, we have expended approximately $75.8 million for the well intervention,
abandonment, decommissioning, and debris removal work performed on the platforms
and production facilities which were destroyed by the storms. The remaining
damage assessment, well intervention, and subsequent debris removal efforts
could continue over the next several years. We estimate that remaining well
intervention, abandonment, and decommissioning efforts associated with the
destroyed platforms and production facilities, as well as the efforts to remove
debris, reconstruct destroyed structures, and redrill associated wells, will be
performed at an additional cost of approximately $95 to $110 million net to our
interest and before any insurance recoveries. Due to the non-routine nature of
the well intervention and debris removal efforts, however, our estimates of the
future cost to perform this work may be understated, possibly
significantly.
19
Approximately $45
to $50 million of the remaining well intervention, abandonment, decommissioning,
and debris removal efforts are associated with the offshore platforms which were
destroyed by Hurricanes Katrina and Rita. An estimate of these costs has been
accrued for as part of Maritech’s decommissioning liability. During the fourth
quarter of 2009, we entered into a settlement agreement with Maritech’s insurers
and other associated parties under which we received approximately $40.0 million
associated with the unreimbursed well intervention costs incurred or to be
incurred. Except for approximately $0.6 million of proceeds expected to be
received in March 2010, no significant additional insurance recoveries of well
intervention, debris removal, or excess property damage costs associated with
Hurricanes Katrina and Rita will be received. Following the collection of these
amounts, we have collected substantially all of the maximum coverage limits
pursuant to our policies.
With regard to the
damages associated with Hurricane Ike, we have performed a significant majority
of the property repairs on the damaged platforms and have performed a portion of
the well intervention work related to the platforms that were destroyed. Despite
our confidence that the repair, well intervention, and debris removal costs will
qualify as covered costs pursuant to our insurance coverage, a portion of these
costs may not be reimbursed. Also, the timing of the collection of any future
reimbursements is beyond our control, and we will continue to use a significant
amount of our working capital until such reimbursements are received. In
addition, a portion of the reimbursements ultimately received may be offset by
legal and other administrative costs incurred in our attempts to collect them.
Our estimates of the remaining costs to be incurred may be imprecise. To the
extent actual future costs exceed the policy maximum for these costs, such
excess costs would not be reimbursable.
For a further
discussion of the remaining costs to repair damage as a result of 2005 and 2008
hurricanes, see Notes to Consolidated Financial Statements, “Note B – Summary of
Significant Accounting Policies,
Repair Costs and Insurance
Recoveries.
”
Our oil and gas production
levels continue to be affected by the 2008 hurricanes.
Our operating cash
flows continue to be affected by the interruption in Maritech’s oil and gas
production as a result of damage to offshore platforms and pipelines caused by
the 2008 hurricanes. One of the destroyed offshore platforms has resulted in the
loss of production from a key producing field which represented 24.3% of our
pre-storm production. During the fourth quarter of 2009, Maritech modified one
of the remaining platforms in this field and has restored a portion of the
interrupted production. The full resumption of production from this field will
require the construction of a new platform and several wells to be redrilled,
and these efforts are estimated to cost approximately $25 to $30 million, before
insurance recoveries, and are not scheduled to be completed until 2011. With
regard to the shut-in production, our insurance protection does not include
business interruption coverage. While repair and recovery efforts have been
prioritized to restore Maritech’s production as soon as possible, these
production restoration efforts are expected to continue into 2011 and beyond.
The full resumption of Maritech’s pre-storm production levels may never
occur.
We may elect to continue to
self-insure windstorm damage to our Maritech assets in the Gulf of Mexico, which
could result in significant uninsured losses.
In
the past, we have maintained windstorm insurance that is designed to cover
damages to our Maritech platforms, equipment, and other assets located in the
Gulf of Mexico. As a result of hurricanes in 2005 and 2008, Maritech suffered
varying levels of damage to a majority of its offshore platforms, and several
platforms were destroyed. Following these storms, insurance premiums and
deductibles for windstorm insurance covering these assets increased
dramatically, and policy limits and sub-limits were decreased dramatically.
During the second quarter of 2009, we determined that the cost of premiums and
the associated deductibles and coverage limits for windstorm damage for
Maritech’s offshore properties made the continuation of such coverage
uneconomical, and Maritech discontinued its insurance coverage for windstorm
damage through May 2010, electing to self-insure for these damages. If premiums,
deductibles, and policy limits for windstorm insurance remain as unfavorable for
the June 2010 through May 2011 season, we may once again choose to retain a
significant amount of hurricane risk. Depending on the severity and location of
any storms during a period in which we are self-insured, uninsured losses could
be significant and could have a material adverse effect on our financial
position, results of operations, and cash flows.
20
There can be no
assurance that future insurance coverage with more favorable deductible and
maximum coverage amounts will be available in the market or that its cost will
be justifiable. There can be no assurance that any insurance will be adequate to
cover losses or liabilities associated with operational hazards. 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, 2009, our total debt outstanding was approximately $310.1
million and our debt to total capital ratio was 35.0%. This debt to total
capital ratio excludes approximately $33.4 million of available cash held as of
December 31, 2009. 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.
Our bank revolving
credit facility is scheduled to mature in June 2011, and our Senior Notes are
scheduled to mature at various dates between September 2011 and April 2016. The
replacement of these capital sources at similar or more favorable terms is
uncertain.
We are exposed to
significant credit risks.
We
face credit risk associated with the significant amounts of accounts receivable
we have with our customers in the energy industry. Many of our
customers, particularly those associated with our onshore operations, are small
to medium-sized oil and gas 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.
Maritech purchases
interests in oil and gas properties in connection with the operations of our
Offshore Division. As the owner and operator of these 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,
if Maritech acquires less than 100% of the working interest in a property, its
co-owners 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.
Our operating results and
cash flows for certain of our subsidiaries are subject to foreign
currency
risk.
The operations of
certain of our subsidiaries are exposed to fluctuations between the U.S. dollar
and certain foreign currencies. Our plans to grow our international operations
could cause this exposure from fluctuating currencies to increase. In
particular, our growing operations in Brazil, as a result of a long-term
contract with Petrobras entered into during 2008, will subject us to increased
foreign currency risk in that country. Historically, exchange rates of foreign
currencies have fluctuated significantly compared to the U.S.
21
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.
Our revolving
credit facility consists of floating rate loans which bear interest at an agreed
upon percentage rate spread above LIBOR. Although as of December 31, 2009, there
is no balance outstanding under the revolving credit facility, there is no
assurance that we will not borrow under the facility in the future. Accordingly,
our cash flows and results of operations are 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 June 2006. The revolving credit
facility is scheduled to mature in June 2011. The terms governing our Senior
Notes were agreed to in September 2004, April 2006, and April 2008, and these
Senior Notes all bear interest at fixed interest rates and are scheduled to
mature at various dates between September 2011 and April 2016. The terms for our
indebtedness were negotiated during a period of historically low interest rates
and credit spreads. There can be no assurance that the financial market
conditions at the times these existing debt agreements are renegotiated will be
on terms as favorable as their current terms.
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 types of government
regulation, including numerous federal and state environmental protection laws
and regulations. These laws and regulations are becoming increasingly complex
and stringent, and compliance is becoming increasingly expensive. Governmental
authorities have the power to enforce compliance with these regulations, and
violators are subject to civil and criminal penalties, including civil fines,
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.
A
large portion of Maritech’s oil and gas operations are conducted on federal
leases that are administered by the Minerals Management Service (MMS) and are
required to comply with the regulations and orders promulgated by the MMS under
the Outer Continental Shelf Lands Act. MMS 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. Under limited circumstances, the MMS
could require us to suspend or terminate our operations on a federal lease. The
MMS also establishes the basis for royalty payments due under federal oil and
natural gas leases through regulations issued under applicable statutory
authority.
Our business
exposes 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 and for oil
and gas producing properties. 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.
22
Legislation currently
pending in the U.S. Congress would establish an economy-wide cap-and-trade
program to reduce U.S. emissions of greenhouse gases. Under this legislation,
EPA would issue a capped and steadily declining number of tradable emissions
allowances to certain major sources of greenhouse gas emissions so that such
sources could continue to emit greenhouse gases into the atmosphere. It is not
possible at this time to predict whether or when the U.S. Congress will pass
climate change legislation, or how any bill approved by Congress may be
reconciled with state and regional requirements. In addition, a variety of
regulatory developments, proposals, or requirements have been introduced and/or
adopted in international regions in which we operate that are focused on
restricting the emission of carbon dioxide, methane, and other greenhouse
gases.
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 related to 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 indirectly 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.
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 proprietary rights may
be violated or compromised, which could damage our
operations.
We
own numerous patents, patent applications, and unpatented trade secret
technologies in the U.S. and certain foreign countries. There can be no
assurance that the steps we have taken to protect our proprietary rights will be
adequate to deter misappropriation of these rights. In addition, independent
third parties may develop competitive or superior technologies.
Our expansion into foreign
countries exposes us to complex regulations and may present us with new
obstacles to growth.
We plan to grow both in the United States and
in foreign countries. We have established operations in, among other countries,
Brazil, Mexico, Argentina, Canada, the United Kingdom, Norway, Finland, Sweden,
and India, and have operating joint ventures in Saudi Arabia, and Libya. 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:
|
·
|
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;
|
|
·
|
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 position in
the affected countries; 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
23
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.
None.
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, flow back testing equipment, and compression equipment. The
following information describes facilities that we leased or owned as of
December 31, 2009. We believe our facilities are adequate for our
present needs.
Fluids Division.
Fluids Division facilities include eight 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
tons per year. The two California locations contain 29 square miles of acreage
containing solar evaporation ponds and leased mineral acreage. In addition, the
Fluids Division also owns and leases brine mineral reserves in
Arkansas.
In addition to the above production plant
facilities, the Fluids Division owns or leases thirty-one service center
facilities, twenty in the United States and eleven internationally. The Fluids
Division also leases eight offices and twenty-nine terminal locations, fifteen
throughout the United States and fourteen internationally.
Offshore Division.
The Offshore Division conducts its operations through seven offices and service
facility locations (six of which are leased) located in Texas and Louisiana. In
addition, the Offshore Services segment owns the following fleet of vessels
which it uses in performing its well abandonment, decommissioning, construction,
and contract diving operations:
|
TETRA
Arapaho
|
Derrick barge
with 800-ton capacity crane
|
|
TETRA
DB-1
|
Derrick barge
with 615-ton capacity crane
|
|
Epic
Diver
|
220-foot dive
support vessel with saturation diving system
|
|
Epic
Explorer
|
210-foot dive
support vessel with saturation diving system
|
|
Epic
Seahorse
|
210-foot dive
support vessel
|
|
Epic
Mariner
|
110-foot dive
support vessel
|
See below for a
discussion of the Offshore Division’s oil and gas property assets.
Production Enhancement
Division.
Production Enhancement Division facilities include fifteen
production testing distribution facilities in the U.S. (thirteen of which are
leased) located in Texas, Colorado, Louisiana, and Pennsylvania. In addition,
the Production Testing segment has leased facilities in Brazil, Mexico, Libya,
Bahrain, India, and Saudi Arabia. Compressco’s facilities include a fabrication
and headquarters facility in Oklahoma, a leased fabrication facility in Alberta,
Canada, a leased service facility in New Mexico, and six sales offices in
Oklahoma, Texas, Colorado, New Mexico, Louisiana, and Canada.
Corporate.
Our
headquarters are located in The Woodlands, Texas, in our 153,000 square foot
office building, which is located on 2.635 acres of land. In addition, we own a
20,000 square foot technical facility to service our Fluids Division
operations.
Oil and Gas
Properties.
The following
tables show, for the periods indicated, reserves and operating information
related to our Maritech subsidiary’s oil and gas interests in developed and
undeveloped leases, all of which are located in
24
the Gulf of Mexico
region. Maritech’s oil and gas operations are a separate segment included within
our Offshore Division. The following table provides a brief description as of
December 31, 2009 of Maritech’s most significant oil and gas
properties:
|
Net
Total
|
|||||||||||||||
|
Proved
|
Net
Proved
|
Productive
|
|||||||||||||
|
Reserves
|
Reserves
Mix
|
Gross
|
Developed
|
Undeveloped
|
Working
|
Production
|
|||||||||
|
(MBOE)
|
Oil%
|
Gas%
|
Wells
|
Acreage
|
Acreage
|
Interest
%
|
Status
|
||||||||
|
Timbalier Bay
Area
|
4,606
|
76%
|
24%
|
67
|
8,270
|
7,174
|
100%
|
Producing
|
|||||||
|
Cimarex
Properties,
|
|||||||||||||||
|
Main
Pass Area
|
2,101
|
13%
|
87%
|
16
|
71,172
|
14,984
|
47% -
100%
|
Producing
|
|||||||
|
East Cameron
328
|
2,024
|
92%
|
8%
|
6
|
5,000
|
-
|
50%
|
Producing
|
|||||||
Production
information for each of these most significant properties during the three years
ended December 31, 2009 is as follows:
|
Year
Ended December 31,
|
|||||
|
2009
|
2008
|
2007
|
|||
|
(MBOE)
|
|||||
|
Timbalier Bay
Area
|
764
|
1,289
|
1,702
|
||
|
Cimarex
Properties,
|
|||||
|
Main
Pass Area
|
1,034
|
580
|
4
|
||
|
East Cameron
328
|
60
|
275
|
403
|
||
See also “Note R –
Supplemental Oil and Gas Disclosures” in the Notes to Consolidated Financial
Statements for additional information.
Oil and Gas Reserves.
Through our Maritech subsidiary, we employ full-time, experienced reservoir
engineers and geologists, who are responsible for determining proved reserves in
conformance with guidelines established by the SEC. These SEC guidelines were
revised effective with the December 31, 2009 information. The impact of the
revision to these reserve guidelines was not considered significant to our
proved oil and gas reserve volumes. The value of the oil and gas reserves was
affected by the impact of the new average pricing requirements. Reserve
estimates were prepared by Maritech engineers, based upon their interpretation
of production performance data and geologic interpretation of sub-surface
information derived from the drilling of wells. In accordance with Maritech’s
documented oil and gas reserve policy as prescribed by our Board of Directors,
the preparation of these reserve estimates is subject to Maritech’s system of
internal control whereby key inputs in preparing reserve estimates, such as oil
and natural gas pricing data, oil and gas property ownership interest
percentages, and data regarding levels of operating, development, and
abandonment costs, are reviewed by Maritech personnel outside of the reserve
engineering department. Reserve estimates are also reviewed by Maritech’s
President, who is also a licensed professional engineer and has overall
responsibility for overseeing the preparation of the proved reserve estimates.
In addition to the complete analysis and review by Maritech’s internal reservoir
engineers, independent petroleum engineers and geologists performed reserve
audits of approximately 80.2% of our proved reserve volumes as of December 31,
2009. The use of the term “reserve audit” is intended only to refer to the
collective application of the engineering and geologic procedures which the
independent petroleum engineering firms were engaged to perform and may be
defined and used differently by other companies.
A
reserve audit is the process of reviewing certain of the pertinent facts
interpreted and assumptions made that have resulted in an estimate of reserves
prepared by others and the rendering of an opinion about the appropriateness of
the methodologies employed, the adequacy and quality of the data relied upon,
the depth and thoroughness of the reserves estimation process, the
classification of reserves appropriate to the relevant definitions used, and the
reasonableness of the estimated reserve quantities. In performing a reserve
audit, an independent petroleum engineering firm meets with our technical staff
to collect all necessary geologic, geophysical, engineering, and economic data,
and performs an independent reserve evaluation. The reserve audit of our oil and
gas reserves involves the rigorous examination of our technical evaluation, as
well as the interpretation and extrapolation of well information such as flow
rates, reservoir pressure declines, and other technical information and
measurements. Maritech’s internal reservoir engineers interpret this data
25
to determine the
nature of the reservoir and, ultimately, the quantity of proved oil and gas
reserves attributable to the specific property. Our proved reserves, as
reflected in this Annual Report, include only quantities that Maritech expects
to recover commercially using current technology, prices, and costs, within
existing economic conditions, operating methods, and governmental regulation.
While Maritech can be reasonably certain that the proved reserves are
economically producible, the timing and ultimate recovery can be affected by a
number of factors, including completion of development projects, reservoir
performance, regulatory approvals, and changes in projections of long-term oil
and gas prices. Revisions can include upward or downward changes in the
previously estimated volumes of proved reserves for existing fields due to
evaluation of (1) already available geologic, reservoir, or production data or
(2) new geologic or reservoir data obtained from wells. Revisions can also occur
associated with significant changes in development strategy, oil and gas prices,
or the related production equipment/facility capacity. Maritech’s independent
petroleum engineers also examined the reserve estimates with respect to reserve
categorization, using the definitions for proved reserves set forth in
Regulation S-X Rule 4-10(a), Staff Accounting Bulletin No. 113, and subsequent
SEC staff interpretations and guidance.
Maritech engaged
Ryder Scott Company, L.P. and DeGolyer and MacNaughton to perform the reserve
audits of a portion of our oil and gas reserves as of December 31, 2009, 2008,
and 2007. Both Ryder Scott Company, L.P. and DeGolyer and MacNaughton are
established oil and gas reservoir engineering firms providing engineering
services worldwide. The staffs of both of these firms, including the personnel
assigned to the reserve audits of Maritech’s reserve estimates, include licensed
reservoir engineers experienced in performing these services. In the conduct of
these reserve audits, these independent petroleum engineering firms did not
independently verify the accuracy and completeness of information and data
furnished by Maritech with respect to property interests owned, oil and gas
production and well tests from examined wells, or historical costs of operation
and development; however, they did verify product prices, geological structural
and isopach maps, along with reservoir data such as well logs, core analyses,
and pressure measurements. If, in the course of the examinations, a matter of
question arose regarding the validity or sufficiency of any such information or
data, the independent petroleum engineering firms did not accept such
information or data until all questions relating thereto were satisfactorily
resolved. Furthermore, in instances where decline curve analysis was not
adequate in determining proved producing reserves, the independent petroleum
engineering firms performed volumetric analysis, which included the analysis of
geologic, reservoir, and fluids data. Proved undeveloped reserves were analyzed
by volumetric analysis, which takes into consideration recovery factors relative
to the geology of the location and similar reservoirs. Where applicable, the
independent petroleum engineering firms examined data related to well spacing,
including potential drainage from offsetting producing wells, in evaluating
proved reserves of undrilled well locations.
The reserve audit
performed by Ryder Scott Company, L.P. included certain properties selected by
Maritech, including all of our significant properties described above, excluding
the Cimarex Properties, and represented approximately 64.0% of our total proved
oil and gas reserve volumes as of December 31, 2009. The reserve audit performed
by DeGolyer and MacNaughton included the Cimarex Properties acquired in December
2007 and represented approximately 16.2% of our total proved oil and gas reserve
volumes as of December 31, 2009. The independent petroleum engineers represent
in their audit reports that they believe Maritech’s estimates of future reserves
were prepared in accordance with generally accepted petroleum engineering and
evaluation principles for the estimation of future reserves in accordance with
SEC standards. In each case, the independent petroleum engineers concluded that
the overall proved reserves for the reviewed properties as estimated by Maritech
were, in the aggregate, reasonable within the established audit tolerance
guidelines of 10% as set forth in the Standards Pertaining to the Estimating and
Auditing of Oil and Gas Reserves Information promulgated by the Society of
Petroleum Engineers (SPE). There were no limitations imposed or encountered by
Maritech or the independent petroleum engineers in the preparation of our
estimated reserves or in the performance of the reserve audits by the
independent petroleum engineers.
Reserve information
is prepared in accordance with guidelines established by the SEC. All of
Maritech’s reserves are located in U.S. state and federal offshore waters in the
Gulf of Mexico region and onshore Louisiana. The following table sets forth
information with respect to our estimated proved reserves as of December 31,
2009:
26
|
Summary
of Oil and Gas Reserves as of December 31, 2009
|
||||||
|
Based
on Average Year Prices
|
||||||
|
Oil
|
Natural
Gas
|
Total
|
||||
|
Reserves
category
|
(MBbls)
|
(MMcf)
|
(MBOE)
|
|||
|
Proved
reserves
|
||||||
|
Developed
|
5,690
|
32,387
|
11,088
|
|||
|
Undeveloped
|
1,383
|
1,124
|
1,570
|
|||
|
Total proved
reserves
|
7,073
|
33,511
|
12,658
|
|||
Maritech’s proved
undeveloped reserves as of December 31, 2009 represent approximately 12.4% of
Maritech’s total proved reserves. Proved undeveloped reserves represented
approximately 12.4% of Maritech total proved reserves as of December 31, 2008.
During 2009, Maritech did not expend any of its development costs to convert
proved undeveloped reserves to proved developed reserves. All of Maritech’s
proved undeveloped reserves as of December 31, 2009 have been classified as
proved undeveloped for less than five years. Maritech has historically developed
its proved undeveloped reserves over a reasonable period of time and anticipates
it will do so in the future, utilizing our future operating cash flows,
available working capital, and if necessary, long-term borrowings.
For additional
information regarding estimates of oil and gas reserves, including estimates of
proved and proved developed reserves, the standardized measure of discounted
future net cash flows, and the changes in discounted future net cash flows, see
“Note R – Supplemental Oil and Gas Disclosures” in the Notes to Consolidated
Financial Statements.
Maritech is not
required to file, and has not filed on a recurring basis, estimates of its total
proved net oil and gas reserves with any U.S. or non-U.S. governmental
regulatory authority or agency other than the Department of Energy (the DOE) and
the SEC. The estimates furnished to the DOE have been consistent with those
furnished to the SEC, however, they are not necessarily directly comparable, due
to special DOE reporting requirements. In no instance have gross reserve volume
information used to prepare the estimates for the DOE differed by more than five
percent from the corresponding estimates reflected in total reserves reported to
the SEC.
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 2009, 2008, and 2007:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Production:
|
||||||||||||
|
Natural
gas (Mcf)
|
10,449,366 | 10,988,840 | 9,515,214 | |||||||||
|
Oil
(Bbls)
|
1,324,815 | 1,466,621 | 1,985,183 | |||||||||
|
Revenues:
|
||||||||||||
|
Natural
Gas
|
$ | 87,905,000 | $ | 99,901,000 | $ | 76,202,000 | ||||||
|
Oil
|
86,286,000 | 107,279,000 | 137,136,000 | |||||||||
|
Total
|
$ | 174,191,000 | $ | 207,180,000 | $ | 213,338,000 | ||||||
|
Average
realized unit prices and production costs:
|
||||||||||||
|
Natural
gas (per Mcf)
|
$ | 8.41 | $ | 9.09 | $ | 8.01 | ||||||
|
Oil
(per Bbl)
|
$ | 65.13 | $ | 73.15 | $ | 69.08 | ||||||
|
Production
cost per equivalent barrel
|
$ | 25.80 | $ | 27.18 | $ | 25.08 | ||||||
|
Depletion
cost per equivalent barrel
|
$ | 25.96 | $ | 25.14 | $ | 20.70 | ||||||
Realized unit
prices include the impact of hedge commodity swap contracts. Production cost per
equivalent barrel excludes the impact of storm repair and insurance related
costs and recoveries, which were charged or credited to operations during each
of the years presented, with approximately $8.2 million, $8.5 million, and $13.5
million being charged in 2009, 2008, and 2007, respectively. Equivalent barrel
(BOE) information is calculated assuming six Mcf of gas is equivalent to one
barrel of oil. Insurance recoveries during 2009 totaled approximately $45.4
million and are excluded from production cost per equivalent barrel for the
year. The 2008 production cost per equivalent barrel was also increased due to
the impact of
27
hurricanes, which
resulted in significant properties being shut-in during the last four months of
2008 and during much of 2009. Depletion cost per equivalent barrel excludes the
impact of dry hole costs and property impairments.
Acreage and Productive
Wells.
At December 31, 2009, 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
|
13
|
1
|
1.20
|
0.10
|
7,468
|
7,123
|
4,169
|
3,855
|
|||||||
|
Louisiana
Offshore
|
42
|
32
|
42.00
|
32.00
|
8,270
|
8,270
|
7,174
|
6,580
|
|||||||
|
Texas
Offshore
|
-
|
-
|
-
|
-
|
7,200
|
1,532
|
-
|
-
|
|||||||
|
Federal
Offshore
|
42
|
55
|
22.50
|
22.30
|
281,972
|
138,136
|
52,482
|
38,022
|
|||||||
|
Total
|
97
|
88
|
65.70
|
54.40
|
304,910
|
155,061
|
63,825
|
48,457
|
|||||||
The majority of
Maritech’s oil and gas properties are held by production. Leases covering
undeveloped acreage other than acreage held by production have expiration terms
ranging from 2010 through 2014.
Drilling Activity.
During 2009, Maritech participated in the drilling of 2 gross development wells
(1.12 net wells) and one gross exploratory well (0.5 net wells), all of which
were productive. Maritech participated in the drilling of 10 gross development
wells (4.3 net wells) during 2008, two of which were unproductive. Maritech
participated in the drilling of 16 gross development wells (11.4 net wells)
during 2007, two of which were unproductive. As of December 31, 2009, one
additional gross exploratory well (1.0 net wells) was in the process of being
drilled. In the first quarter of 2010, Maritech sold a 50% working interest in
this well to a partner. As of December 31, 2008, one additional gross well (0.5
net wells) was in the process of being drilled. As of December 31, 2007, there
were 5 additional wells (2.5 net wells) in the process of being
drilled.
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 reasonably expect these matters to have a material adverse
impact on the financial statements.
Insurance Litigation -
Through December 31, 2009, we have expended approximately $55.2 million
on well intervention and debris removal work primarily associated with the three
Maritech offshore platforms and associated wells which were destroyed as a
result of Hurricanes Katrina and Rita in 2005. As a result of submitting claims
associated with well intervention costs expended during 2006 and 2007 and
responding to underwriters’ requests for additional information, approximately
$28.9 million of these well intervention costs were reimbursed; however, our
insurance underwriters maintained that well intervention costs for certain of
the damaged wells did not qualify as covered costs and certain well intervention
costs for qualifying wells were not covered under the policy. In addition, the
underwriters also maintained that there was no additional coverage provided
under an endorsement we obtained in August 2005 for the cost of debris removal
associated with these platforms or for other damage repairs associated with
Hurricanes Katrina and Rita on certain properties in excess of the insured
values provided by the property damage section of the policy. Although we
provided requested information to the underwriters and had numerous discussions
with the underwriters, brokers, and insurance adjusters, we did not receive the
requested reimbursement for these contested costs. As a result, on November 16,
2007, we filed a lawsuit in Montgomery County, Texas, entitled
Maritech Resources, Inc. v. Certain
Underwriters and Insurance Companies at Lloyd’s, London subscribing to Policy
no. GA011150U and Steege Kingston
, in which we sought damages for breach
of contract and various related claims and a declaration of the extent of
coverage of an endorsement to the policy. We also made an alternative claim
against our insurance broker, based on its procurement of the August 2005
endorsement, and a separate claim against underwriters’ insurance adjuster for
its role in handling the insurance claim.
28
During October
2009, we entered into a settlement agreement with regard to this lawsuit, under
which we received approximately $40.0 million during the fourth quarter of 2009
associated with the August 2005 endorsement and well intervention costs incurred
or to be incurred from Hurricanes Katrina and Rita. Except for approximately
$0.6 million of proceeds expected to be received in March 2010, no significant
additional insurance recoveries of well intervention, debris removal, or excess
property damage costs associated with Hurricanes Katrina and Rita will be
received. Following the collection of these amounts, we have collected
approximately $136.6 million of insurance proceeds associated with damage from
Hurricanes Katrina and Rita. This amount represents substantially all of the
maximum coverage limits pursuant to our policies. We estimate that future well
intervention, abandonment, decommissioning, and debris removal efforts related
to these destroyed platforms will result in approximately $45 million to $50
million of additional costs, and an estimate of these costs has been accrued for
as part of Maritech’s decommissioning liability. As a result of the resolution
of this contingency, the full amount of settlement proceeds is reflected as a
credit to earnings in the fourth quarter of 2009.
Class Action Lawsuit -
Between March 27, 2008 and April 30, 2008, two putative class action
complaints were filed in the United States District Court for the Southern
District of Texas (Houston Division) against us and certain of our officers by
certain stockholders on behalf of themselves and other stockholders who
purchased our common stock between January 3, 2007 and October 16, 2007. The
complaints assert claims under Sections 10(b) and 20(a) of the Securities
Exchange Act of 1934, as amended, and Rule 10b-5 promulgated thereunder. The
complaints allege that the defendants violated the federal securities laws
during the period by, among other things, disseminating false and misleading
statements and/or concealing material facts concerning our current and
prospective business and financial results. The complaints also allege that, as
a result of these actions, our stock price was artificially inflated during the
class period, which enabled our
insiders to sell
their personally-held shares for a substantial gain. The complaints seek
unspecified compensatory damages, costs, and expenses. On May 8, 2008, the Court
consolidated these complaints as
In re TETRA Technologies, Inc.
Securities Litigation,
No. 4:08-cv-0965 (S.D. Tex.). On August 27, 2008,
Lead Plaintiff Fulton County Employees’ Retirement System filed its Amended
Consolidated Complaint. On October 28, 2008, we filed a motion to dismiss the
federal class action. On July 9, 2009, the Court issued an opinion dismissing,
without prejudice, most of the claims in this lawsuit but permitting plaintiffs
to proceed on their allegations regarding disclosures pertaining to the
collectability of certain insurance receivables.
Between May 28,
2008 and June 27, 2008, two petitions were filed by alleged stockholders in the
District Courts of Harris County, Texas, 133
rd
and
113
th
Judicial Districts, purportedly on our behalf. The suits name our directors and
certain officers as defendants. The factual allegations in these lawsuits mirror
those in the class action lawsuit, and the claims are for breach of fiduciary
duty, unjust enrichment, abuse of control, gross mismanagement, and waste of
corporate assets. The petitions seek disgorgement, costs, expenses, and
unspecified equitable relief. On September 22, 2008, the 133
rd
District Court consolidated these complaints as
In re TETRA Technologies, Inc.
Derivative Litigation,
Cause No. 2008-23432 (133
rd
Dist. Ct., Harris County, Tex.), and appointed Thomas Prow and Mark Patricola as
Co-Lead Plaintiffs. This lawsuit was stayed by agreement of the parties pending
the Court’s ruling on our motion to dismiss the federal class action. On
September 8, 2009, the plaintiffs in this state court action filed a
consolidated petition which makes factual allegations similar to the surviving
allegations in the federal lawsuit.
At
this stage, it is impossible to predict the outcome of these proceedings or
their impact upon us. We currently believe that the allegations made in the
federal complaints and state petitions are without merit, and we intend to seek
dismissal of and vigorously defend against these actions. While a successful
outcome cannot be guaranteed, we do not reasonably expect these lawsuits to have
a material adverse effect.
29
Price
Range of Common Stock
Our common stock is
traded on the New York Stock Exchange under the symbol “TTI.” As of February 23,
2010, there were approximately 10,800 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, 2009, as reported by
the New York Stock Exchange.
|
High
|
Low
|
|||||||
|
2009
|
||||||||
|
First
Quarter
|
$ | 6.28 | $ | 1.94 | ||||
|
Second
Quarter
|
10.44 | 3.01 | ||||||
|
Third
Quarter
|
10.74 | 6.79 | ||||||
|
Fourth
Quarter
|
11.62 | 8.70 | ||||||
|
2008
|
||||||||
|
First
Quarter
|
$ | 19.38 | $ | 13.56 | ||||
|
Second
Quarter
|
25.00 | 14.72 | ||||||
|
Third
Quarter
|
24.02 | 5.69 | ||||||
|
Fourth
Quarter
|
7.24 | 3.12 | ||||||
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, 2004, 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.
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
30
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, 2007, 2008, or 2009 pursuant to the repurchase
program. Shares repurchased during the fourth quarter of 2009 other than
pursuant to our repurchase program are as follows:
|
Period
|
Total
Number of Shares Purchased
|
Average
Price Paid per Share
|
Total
Number of Shares Purchased as Part of Publicly Announced Plans or
Programs
(1)
|
Maximum
Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased
Under the Publicly Announced Plans or Programs
(1)
|
||||||||||||
|
Oct
1 - Oct 31, 2009
|
- | $ | - | - | $ | 14,327,000 | ||||||||||
|
Nov
1 - Nov 30, 2009
|
1,929 | (2) | $ | 10.01 | - | $ | 14,327,000 | |||||||||
|
Dec
1 - Dec 31, 2009
|
- | $ | - | - | $ | 14,327,000 | ||||||||||
|
Total
|
1,929 | - | $ | 14,327,000 | ||||||||||||
|
(1)
|
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.
|
|
(2)
|
Shares we
received in connection with the vesting of certain employee restricted
stock. These shares were not acquired pursuant to the stock repurchase
program.
|
The following tables set forth our selected
consolidated financial data for the years ended December 31, 2009, 2008, 2007,
2006, and 2005. 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 11 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 2007, we
completed the acquisition of two service companies and Maritech acquired certain
oil and gas properties.
During 2006, we
completed the acquisitions of the operations of Epic Divers, Inc., Beacon
Resources, LLC, and a heavy lift barge. During 2005, we acquired certain oil and
gas properties as part of our Maritech subsidiary’s operations. These
acquisitions significantly impact the comparison of our financial statements for
2009 to earlier years. In December 2007, we sold our process services
operations.
In
2006, we made the decision to discontinue our Venezuelan fluids and production
testing operations. In 2003, we made the decision to discontinue the operations
of our Norwegian process services operations. During 2000, we commenced our exit
from the micronutrients business. Accordingly, we have reflected each of the
above operations as discontinued operations. During 2008, we recorded
significant impairments of oil and gas properties, goodwill, and other
long-lived assets. During 2007, we recorded significant impairments of our oil
and gas properties.
31
|
Year
Ended December 31,
|
||||||||||||||||||||
|
2009
|
2008
|
2007
|
2006
|
2005
|
||||||||||||||||
|
(In
Thousands, Except Per Share Amounts)
|
||||||||||||||||||||
|
Income
Statement Data
|
||||||||||||||||||||
|
Revenues
|
$ | 878,877 | $ | 1,009,065 | $ | 982,483 | $ | 767,795 | $ | 509,249 | ||||||||||
|
Gross
profit
|
213,097 | 152,001 | 116,383 | 252,804 | 123,672 | (1) | ||||||||||||||
|
Operating
income (loss)
|
112,265 | (21 | ) | 16,512 | 160,800 | 54,317 | ||||||||||||||
|
Interest
expense
|
(13,207 | ) | (17,557 | ) | (17,886 | ) | (13,637 | ) | (6,310 | ) | ||||||||||
|
Interest
income
|
417 | 779 | 731 | 348 | 330 | |||||||||||||||
|
Other income
(expense), net
|
5,895 | 12,884 | 2,805 | 4,858 | 3,692 | |||||||||||||||
|
Income (loss)
before discontinued
|
||||||||||||||||||||
|
operations
|
68,807 | (9,655 | ) | 1,221 | 99,880 | 34,802 | ||||||||||||||
|
Net income
(loss)
|
$ | 68,804 | $ | (12,136 | ) | $ | 28,771 | $ | 101,878 | $ | 38,062 | |||||||||
|
Income (loss)
per share, before
|
||||||||||||||||||||
|
discontinued
operations
(2)
|
$ | 0.92 | $ | (0.13 | ) | $ | 0.02 | $ | 1.39 | $ | 0.51 | |||||||||
|
Average
shares
(2)
|
75,045 | 74,519 | 73,573 | 71,631 | 68,588 | |||||||||||||||
|
Income (loss)
per diluted share, before
|
||||||||||||||||||||
|
discontinued
operations
(2)
|
$ | 0.91 | $ | (0.13 | ) | $ | 0.02 | $ | 1.33 | $ | 0.48 | |||||||||
|
Average
diluted shares
(2)
|
75,722 | (3) | 74,519 | (4) | 75,921 | (5) | 74,824 | 72,137 | ||||||||||||
|
(1)
|
Gross profit for this period reflects the reclassification of certain billed operating costs as cost of revenues, which had previously been credited to general and administrative expense. The reclassified amount was $1,113 for 2005. |
|
(2)
|
Net income (loss) per share and average share outstanding information reflects the retroactive impact of a 2-for-1 stock split as of May 15, 2006, and a 3-for-2 stock split as of August 19, 2005. Each of the stock splits was effected in the form of a stock dividend as of the record dates. |
|
(3)
|
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. |
| (4) | For the year ended December 31, 2008, 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 period. |
| (5) | For the year ended December 31, 2007, the calculation of average diluted shares outstanding excludes the impact of 716,354 average outstanding stock options that would have been antidilutive. |
|
December
31,
|
||||||||||||||||||||
|
2009
|
2008
|
2007
|
2006
|
2005
|
||||||||||||||||
|
(In
Thousands)
|
||||||||||||||||||||
|
Balance
Sheet Data
|
||||||||||||||||||||
|
Working
capital
|
$ | 148,343 | $ | 222,832 | $ | 181,441 | $ | 262,572 | $ | 135,989 | ||||||||||
|
Total
assets
|
1,347,599 | 1,412,624 | 1,295,536 | 1,086,190 | 726,850 | |||||||||||||||
|
Long-term
debt
|
310,132 | 406,840 | 358,024 | 336,381 | 157,270 | |||||||||||||||
|
Decommissioning
and other
|
||||||||||||||||||||
|
long-term
liabilities
|
218,498 | 277,482 | 247,543 | 167,671 | 150,570 | |||||||||||||||
|
Stockholders'
equity
|
$ | 576,494 | $ | 515,821 | $ | 447,919 | $ | 420,380 | $ | 284,147 | ||||||||||
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. We have
accounted for the discontinuance or disposal of certain businesses as
discontinued operations and have adjusted prior period financial information to
exclude these businesses from continuing operations.
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.
32
Business
Overview
Despite a decrease
in consolidated revenues during 2009 compared to the prior year, our overall
profitability increased, primarily due to the unprecedented favorable
performance of our Offshore Services segment, a favorable insurance litigation
settlement, and due to significant impairments to oil and gas properties and
goodwill during 2008. The demand for diving, platform decommissioning, cutting,
and abandonment services continued to be strong during the year following the
damage to offshore platforms from hurricanes in the Gulf of Mexico in prior
years and due to the risk of damage from future storms. This increased demand
plus the additional efficiencies resulting from high utilization and optimal
weather conditions during most of 2009 significantly benefitted the Offshore
Services segment. We expect demand for these services to continue to be robust
in 2010. Maritech’s revenues decreased during 2009 due to lower oil and gas
pricing compared to 2008, despite having a large portion of the impact of
decreased pricing offset by Maritech’s oil and gas hedge contracts. In addition,
Maritech’s oil and gas production volumes decreased compared to the prior year
due to the reduction in development activities over the past year and due to the
continuing impact from Hurricane Ike in 2008, which shut-in production from a
significant oil producing field. Despite these decreases in revenue, Maritech’s
profitability increased compared to 2008 primarily due to the October 2009
settlement agreement with the various parties to our insurance litigation
regarding certain costs associated with Maritech offshore platforms which were
damaged or destroyed by Hurricanes Katrina and Rita during 2005. This settlement
resulted in approximately $40.0 million of settlement gain during 2009. These
increases in profitability were partially offset by the results of our
Production Testing, Compressco, and Fluids operations, which experienced
decreased demand from customers during 2009, resulting in decreased revenues and
profitability. Although these operations continue to be affected by the
lingering impact of the current global economic environment, we expect modest
increases for these operations beginning in 2010 as a result of improving oil
and gas commodity pricing and rig count levels, which are expected to result in
increased activity for our customers. All of our businesses took steps during
2009 to reduce operating and administrative costs through temporary salary
reductions, project deferrals, consolidation of locations, and other measures,
and intend to continue to seek additional ways to maximize earnings and cash
flow going forward.
The current cost
reduction efforts also include a focus on improving cash flow and enhancing
liquidity through a combination of reducing or deferring capital expenditures
and carefully managing working capital. As a result of these efforts, and
despite the difficult market environment for many of our businesses, operating
cash flows increased compared to the prior year to approximately $272.3 million,
and investing activities decreased compared to the prior year to $149.7 million.
During the fourth quarter of 2009 we repaid the remaining outstanding balance
under our bank revolving credit facility and accumulated approximately $33.4
million of
available cash as of December 31, 2009. These efforts were accomplished despite
expending approximately $149.7 million of capital expenditures and other
investing activities during 2009, including $65.9 million for the continuing
construction of our new El Dorado, Arkansas, calcium chloride plant facility,
compared to $56.6 million during 2008. The El Dorado facility began production
during the fourth quarter of 2009 and is expected to further increase the Fluids
Division’s efficiency in manufacturing its chemicals and completion fluids
products, which should strengthen operating cash flows in future years. In
addition, we made significant progress during 2009 in the abandonment and
decommissioning of many of Maritech’s offshore oil and gas property assets,
expending approximately $79.5 million. These abandonment and decommissioning
efforts are expected to continue to be significant going forward. As of December
31, 2009, Maritech has remaining decommissioning liabilities of approximately
$218.4 million, including the remaining well intervention, abandonment,
decommissioning and debris removal work to be done associated with offshore
platforms destroyed by 2005 and 2008 hurricanes. In addition to the $40.0
million proceeds related to our insurance litigation settlement, we also
generated additional cash from the liquidation of certain hedge derivative
contracts and from sales of certain non-strategic assets. Given the expected
prolonged economic recovery for certain of our businesses, we plan to continue
to review future capital expenditures carefully as we also monitor the expected
improvement of our operations. Despite this focus on conserving capital
resources, we continue to seek strategic growth opportunities, both through
acquisitions and internal growth, which we plan to fund from operating cash
flows, and if necessary, from additional long-term debt borrowing. We continue
to have availability under our bank revolving credit facility, which is
scheduled to mature in June 2011. Our Senior Notes are scheduled to mature at
various dates from September 2011 through April 2016.
Future demand for
our products and services depends primarily on activity in the oil and gas
exploration and production industry, which is significantly affected by that
industry’s level of expenditures for the exploration and production of oil and
gas reserves and for the plugging and decommissioning of abandoned oil and gas
properties. Industry expenditures, as indicated by rig count statistics and
other
33
measures, have
recently begun to increase following the significant decline during the past
year which was
in response to the
general uncertainty regarding availability of capital resources in the current
economic environment and due to oil and natural gas price volatility. Our
overall growth remains hampered by the
current decreased
industry demand for many of our products and services, although we still believe
that there are growth opportunities for our products and services in the U.S.
and international markets, supported primarily by:
|
·
|
increases in
technologically-driven deepwater gas well completions in the Gulf of
Mexico;
|
|
·
|
continued
reservoir depletion in the U.S. and the advancing age of offshore
platforms in the Gulf of Mexico, which will drive abandonment and
decommissioning work; and
|
|
·
|
increasing
development of oil and gas reserves
abroad.
|
Our Fluids Division
generates revenues and cash flows by manufacturing and selling clear brine
completion fluids (CBFs) and providing filtration, water transfer, and
associated products and engineering services to U.S. and international
exploration and production companies. In addition, the Fluids Division also
provides 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. Fluids Division revenues decreased 23.1% during
2009 compared to the prior year, due primarily to a significant decrease in
sales volumes, both of its CBF products and its other manufactured chemicals,
primarily due to decreased energy industry demand. The overall outlook for the
Division’s completion services business is dependent on the level of oil and gas
drilling activity, particularly in the Gulf of Mexico, which has remained flat
or has decreased during the past several years due largely to the maturity of
the producing fields in the heavily developed portions of the Gulf of Mexico.
Overall industry drilling activity during 2009 was also negatively impacted by
lower oil and natural gas prices during much of the year compared to 2008 and
increased capital constraints as a result of the general economic conditions. We
anticipate modest increases in spending beginning in 2010 given the current
levels of oil and natural gas prices. Also, the Division is attempting to
capitalize on the current industry trend toward drilling deepwater wells that
generally require greater volumes of more expensive brine solutions. In
addition, we are also pursuing specific international opportunities where
industry spending levels from major energy customers and national oil companies
have generally been more stable. During 2008, the Fluids Division entered into a
long-term contract with Petroleo Brasileiro S.A. (Petrobras) to provide
completion fluids for its deepwater drilling program offshore Brazil. Although
much of Petrobras’ activity associated with this contract was deferred during
2009, we anticipate that activity in Brazil will be increasing beginning in
2010. To further the growth of the Division’s manufactured products operation
and provide additional internally produced supply for our completion fluids
operations, in 2007 we began construction of a new calcium chloride plant
facility located near El Dorado, Arkansas. During the fourth quarter of
2009, we began production of liquid
calcium chloride at
our newly completed calcium chloride plant. This plant also began production of
dry (flake) calcium chloride during January 2010.
Our Offshore
Division consists of two operating segments: the Offshore Services segment and
the Maritech segment. Offshore Services generates revenues and cash flows by
performing (1) downhole and subsea services such as plugging and abandonment,
workover, and wireline services, (2) construction and decommissioning services,
including hurricane damage remediation, and (3) diving services involving
conventional and saturated air diving and the operation of several dive support
vessels. The services provided by the Offshore Services segment are marketed
primarily in the Gulf Coast region of the U.S., including offshore, inland
waters, and in certain onshore locations. Gulf of Mexico platform
decommissioning and well abandonment activity levels are driven primarily by MMS
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.
In addition, the segment continues to capitalize on the current demand for well
abandonment and decommissioning services in the Gulf of Mexico, including a
portion of the work to be performed over the next several years on offshore
properties that were damaged or destroyed by the significant hurricanes that
occurred in 2005 and 2008. Given the increasing cost to insure offshore
properties, many oil and gas operators are accelerating their plans to abandon
and decommission their offshore wells and platforms. Offshore Services revenues
increased by 15.5% during 2009 primarily associated with the increased
utilization, particularly by the segment’s diving, abandonment, heavy lift, and
cutting services businesses which continue to enjoy high demand following the
2005 and 2008 hurricanes. In addition, the segment benefitted from near-optimal
weather conditions during most of 2009. Although it expects robust demand for
its services to continue, the segment anticipates its overall activity in 2010
will decrease from the record levels experienced during 2009, as the remaining
hurricane remediation work moves at a less urgent pace and due to an expected
return to normal levels of weather disruptions.
34
Through Maritech
and its subsidiaries, the Offshore Division acquires, manages, explores, and
develops oil and gas properties in the offshore, inland water, and onshore
region of the Gulf of Mexico and generates revenues and cash flows from the sale
of the associated oil and natural gas production volumes. Maritech periodically
acquires properties for their exploration and development potential. During
2009, Maritech’s operations continued to be hampered by production interruptions
from the 2008 hurricanes, reduced funding for capital expenditures, and the need
to perform significant well intervention and decommissioning efforts. Maritech
has five remaining toppled offshore platforms that will require extensive
efforts to decommission, and much of this work is planned for 2010. Maritech’s
revenues during 2009 decreased by 15.1% compared to 2008, due to decreased
overall production and lower oil and gas commodity prices compared to 2008.
Although much of the storm-interrupted production has been restored, one of the
destroyed offshore platforms served a key producing field, the East Cameron 328
field. Although a portion of the production from this field has been restored,
the complete restoration of East Cameron 328 production will require the
reconstruction of the destroyed platform and the redrilling of wells, and these
efforts are not expected to be complete until 2011. Maritech’s existing lease
portfolio, along with exploitation opportunities on producing leases, should
continue to provide Maritech with additional attractive development projects,
subject to capital expenditure constraints as a result of the current economic
environment.
Our Production
Enhancement Division consists of two operating segments: the Production Testing
segment and Compressco segment. The Production Testing segment generates
revenues and cash flows by performing flow back pressure, volume testing, and
other services for oil and gas producers. The primary testing markets served
include many of the major oil and gas basins in the United States as well as
onshore basins in Mexico, Brazil, Northern Africa, the Middle East, and certain
other international markets. 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 which the Production Testing
segment serves. Production Testing segment revenues decreased 36.6% in 2009 as
compared to 2008, primarily due to decreased demand in the United States. Given
the recent increase in oil and natural gas pricing, we expect demand for our
production testing services will increase in 2010 compared to 2009.
Compressco
generates revenues and cash flows by performing wellhead compression-based
production enhancement services throughout many of the onshore producing regions
of the United States, as well as basins in Canada, Mexico, South America,
Europe, Asia, and other international locations. Demand for wellhead compression
services is generally driven by the need to boost production in certain mature
gas wells with declining production. Compressco segment revenues decreased 9.6%
in 2009 as compared to 2008, due to decreased U.S. and international demand for
production enhancement services, primarily
resulting from
decreased natural gas prices. Given the recent increase in oil and natural gas
prices, we anticipate Compressco’s 2010 revenues and cash flows will increase
compared to 2009, particularly as we also continue to seek new U.S. and
international markets for Compressco operations.
Critical
Accounting Policies and Estimates
In
preparing our consolidated financial statements, we make assumptions, estimates,
and judgments that affect the amounts reported. 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. Our estimates are based on historical experience and on
future expectations which we believe are reasonable. The fair values of large
portions of our total assets and liabilities are measured using significant
unobservable inputs. The combination of these factors forms the basis for
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
35
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 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. Our estimates
of operating cash flows and fair values for assets impaired have generally been
accurate. Although we have historically had minimal impairments of long-lived
assets other than for oil and gas properties (see separate discussion below),
during 2009 we recorded other long-lived asset impairments of $8.1 million.
Given the current volatile economic environment, the likelihood of additional
material impairments of long-lived assets in future periods is higher due to the
possibility of further 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. The assessment for goodwill impairment
is performed for each reporting unit and consists of a comparison of the
carrying amount of each reporting unit to our estimation of the fair value of
that reporting unit. 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 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. During the fourth quarter of 2008, due to changes in the
global economic environment which affected our stock price and market
capitalization, we recorded an impairment of goodwill of $47.1 million. We
believe our estimates of the fair value for each reporting unit are reasonable.
However, given the current volatile economic environment, the likelihood of
additional material impairments of goodwill in future periods is
higher.
As
of December 31, 2009, our Offshore Services, Production Testing, and Compressco
reporting units reflect goodwill in the amounts of $3.8 million, $23.0 million,
and $72.2 million, respectively. The fair values of our Offshore Services and
Production Testing reporting units significantly exceed their carrying
values. However,
because the estimated fair value of our Compressco reporting unit currently
exceeds its carrying value by approximately 14.8%, there is a reasonable
possibility that Compressco’s goodwill may be impaired in a future period, and
the amount of such impairment may be material. Specific uncertainties affecting
the estimated fair value of our Compressco reporting unit include the prices
received by Compressco’s customers for natural gas production, the rate of
future growth of Compressco’s business, and the need and timing of the full
resumption of the fabrication of new Compressco Gas Jack
®
compressor units. The demand for Compressco’s wellhead compression services has
been negatively affected by the global economic environment and the decrease in
natural gas prices compared to the prior year. Further decreases in such demand
could have a further negative effect on the fair value of our Compressco
reporting unit.
Oil and Gas Properties –
Maritech accounts for its interests in oil and gas properties using the
successful efforts method, whereby costs incurred to drill and equip development
wells, including unsuccessful development wells, are capitalized, and costs
related to unsuccessful exploratory wells are expensed as incurred. All
capitalized costs are accumulated and recorded separately for each field and are
depleted on a unit-of-production basis, based on the estimated remaining proved
oil and gas reserves of each field. Oil and gas properties are assessed for
impairment in value on an individual field basis, whenever indicators become
evident, with any impairment charged to expense. Accordingly, Maritech’s results
of operations may be more volatile compared to those oil and gas exploration and
production companies who account for their operations using the full-cost
method. Due to the impact of changing oil and gas prices, results of drilling
and development efforts, and increased estimated decommissioning liabilities
(see discussion below), Maritech has recorded oil and gas property impairments
and dry hole costs, and during 2007, 2008, and 2009 these impairment charges
were significant. Maritech periodically purchases oil and gas properties and
assumes the associated well abandonment and decommissioning liabilities. Any
significant differences in the actual amounts of oil and gas production cash
flows produced or decommissioning costs
36
incurred compared
to the estimated amounts recorded will affect our anticipated profitability.
Given the current volatility of oil and natural gas prices, we are more likely
to record additional significant impairments in future periods.
The process of
estimating oil and gas reserves is complex, requiring significant decisions and
assumptions in the evaluation of available geological, geophysical, engineering,
and economic data for each reservoir. As a result, these estimates are
inherently imprecise. Actual future production, cash flows, development
expenditures, operating and abandonment expenses, and quantities of recoverable
oil and gas reserves may vary substantially from those initially estimated by
Maritech. Any significant variance in these assumptions could result in
significant upward or downward revisions of previous estimates, as reflected in
our annual disclosure of the estimated quantity and value of our proved
reserves. In previous years, we have reflected revisions to our previous
estimates of reserve quantities and values, and in some years, these revisions
have been significant. It is possible we will have additional revisions to our
estimated quantities of proved reserves in future periods.
Decommissioning Liabilities –
We estimate the third-party market values (including an estimated profit
to the service provider) to plug and abandon the wells, decommission the
pipelines and platforms, and clear the sites, and we use these estimates to
record Maritech’s well abandonment and decommissioning liabilities. These well
abandonment and decommissioning liabilities (referred to as decommissioning
liabilities) are recorded net of amounts allocable to joint interest owners,
anticipated insurance recoveries, 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 utilizes the services of its affiliated companies
to perform well abandonment and decommissioning work. When these services are
performed by an affiliated company, all recorded intercompany revenues are
eliminated in the consolidated financial statements. Any profit we earn in
performing such abandonment and decommissioning operations on Maritech’s
properties is recorded as the work is performed. 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 additional profit
on the project and included in earnings in the period in which the project is
completed. Conversely, actual costs in excess of the decommissioning liability
are charged against earnings in the period in which the work is
performed.
We
review the adequacy of our decommissioning liability whenever indicators suggest
that either the amount or timing of the estimated cash flows underlying the
liability have changed materially. The estimated timing of these cash flows is
determined by the productive life of the associated oil and gas property, which
is
based on the
property’s oil and gas reserve estimates. The amount of cash flows necessary to
abandon and decommission the property is subject to changes due to seasonal
demand, increased demand following hurricanes, and other general changes in the
energy industry environment. Accordingly, the estimation of our decommissioning
liability is imprecise. The estimation of the decommissioning liability
associated with the five 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 decommissioning work has often exceeded our
initial estimate of Maritech’s decommissioning liability and has resulted in
charges to earnings in the period the work is performed or when the additional
liability is recorded. During 2008 and 2009, the amount of charges to earnings
as a result of costs in excess of our estimated liabilities has been
significant. To the extent our decommissioning liability is 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 turnkey charges or specific time, material, and equipment charges,
which are billed in accordance with the terms of such contracts. With regard to
turnkey 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 turnkey 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.
37
Bad Debt Reserves –
Reserves
for bad debts are calculated on a specific identification basis, whereby we
estimate whether or not specific accounts receivable will be collected. Such
estimates of future collectability may be incorrect, which could result in the
recognition of unanticipated bad debt expenses in future periods. A significant
portion of our revenues come from oil and gas exploration and production
companies, and historically our estimates of uncollectible receivables have
proven reasonably accurate. However, if due to adverse circumstances, such as in
the current economic environment, certain customers are unable to repay some or
all of the amounts owed us, an additional bad debt allowance may be required,
and such amount may be material.
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, 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.
Stock-Based Compensation
–We
estimate the fair value of share-based payments of stock options using the
Black-Scholes option-pricing model. This option-pricing model requires a number
of assumptions, of which the most significant are: expected stock price
volatility, the expected pre-vesting forfeiture rate, and the expected option
term (the amount of time from the grant date until the options are exercised or
expire). Expected volatility is calculated based upon actual historical stock
price movements over the most recent periods equal to the expected option term.
Expected pre-vesting forfeitures are estimated based on actual historical
pre-vesting forfeitures over the most recent periods for the expected option
term. All of these estimates are inherently imprecise and may result in
compensation cost being recorded that is materially different from the actual
fair value of the stock options granted. While the assumptions for expected
stock price volatility and pre-vesting forfeiture rates are updated with each
year’s option-valuing process, there have not been significant revisions made in
these estimates to date.
38
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.
|
Percentage
of Revenues
|
Period-to-Period
|
|||||||||||||||||||
|
Year
Ended December 31,
|
Change
|
|||||||||||||||||||
|
Consolidated
Results of Operations
|
2009
|
2008
|
2007
|
2009 vs
2008
|
2008 vs
2007
|
|||||||||||||||
|
Revenues
|
100.0 | % | 100.0 | % | 100.0 | % | (12.9 | %) | 2.7 | % | ||||||||||
|
Cost of
revenues
|
75.8 | % | 84.9 | % | 88.2 | % | (22.3 | %) | (1.0 | %) | ||||||||||
|
Gross
profit
|
24.2 | % | 15.1 | % | 11.8 | % | 40.2 | % | 30.6 | % | ||||||||||
|
General and
administrative expense
|
11.5 | % | 10.4 | % | 10.2 | % | (3.9 | %) | 5.1 | % | ||||||||||
|
Operating
income (loss)
|
12.8 | % | 0.0 | % | 1.7 | % |
NM
|
(100.1 | %) | |||||||||||
|
Interest
expense
|
1.5 | % | 1.7 | % | 1.8 | % | (24.8 | %) | (1.8 | %) | ||||||||||
|
Interest
income
|
0.0 | % | 0.1 | % | 0.1 | % | (46.5 | %) | 6.6 | % | ||||||||||
|
Other income
(expense), net
|
0.7 | % | 1.3 | % | 0.3 | % | (54.2 | %) | 359.3 | % | ||||||||||
|
Income (loss)
before income taxes and
|
||||||||||||||||||||
|
discontinued
operations
|
12.0 | % | (0.4 | %) | 0.2 | % |
NM
|
(281.1 | %) | |||||||||||
|
Net income
(loss) before discontinued operations
|
7.8 | % | (1.0 | %) | 0.1 | % |
NM
|
(890.7 | %) | |||||||||||
|
Discontinued
operations, net of tax
|
(0.0 | %) | (0.2 | %) | 2.8 | % | (99.9 | %) | (109.0 | %) | ||||||||||
|
Net income
(loss)
|
7.8 | % | (1.2 | %) | 2.9 | % |
NM
|
(142.2 | %) | |||||||||||
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(In
Thousands)
|
||||||||||||
|
Revenues
|
||||||||||||
|
Fluids
Division
|
$ | 225,517 | $ | 293,248 | $ | 282,074 | ||||||
|
Offshore
Division
|
||||||||||||
|
Offshore
Services
|
353,798 | 306,362 | 341,082 | |||||||||
|
Maritech
|
177,039 | 208,509 | 214,154 | |||||||||
|
Intersegment
eliminations
|
(45,648 | ) | (22,971 | ) | (29,057 | ) | ||||||
|
Total
|
485,189 | 491,900 | 526,179 | |||||||||
|
Production
Enhancement Division
|
||||||||||||
|
Production
Testing
|
80,557 | 127,019 | 93,130 | |||||||||
|
Compressco
|
88,108 | 97,417 | 83,554 | |||||||||
|
Total
|
168,665 | 224,436 | 176,684 | |||||||||
|
Intersegment
eliminations
|
(494 | ) | (519 | ) | (2,454 | ) | ||||||
| 878,877 | 1,009,065 | 982,483 | ||||||||||
|
Gross
profit
|
||||||||||||
|
Fluids
Division
|
$ | 47,549 | $ | 56,446 | $ | 38,620 | ||||||
|
Offshore
Division
|
||||||||||||
|
Offshore
Services
|
94,488 | 43,025 | 49,110 | |||||||||
|
Maritech
|
20,655 | (29,958 | ) | (45,631 | ) | |||||||
|
Intersegment
eliminations
|
571 | (782 | ) | 6,225 | ||||||||
|
Total
|
115,714 | 12,285 | 9,704 | |||||||||
|
Production
Enhancement Division
|
||||||||||||
|
Production
Testing
|
19,164 | 44,413 | 32,813 | |||||||||
|
Compressco
|
33,689 | 41,323 | 36,685 | |||||||||
|
Total
|
52,853 | 85,736 | 69,498 | |||||||||
|
Other
|
(3,019 | ) | (2,466 | ) | (1,439 | ) | ||||||
| 213,097 | 152,001 | 116,383 | ||||||||||
39
| Year Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (In Thousands) | ||||||||||||
|
Income
(loss) before taxes and discontinued operations
|
||||||||||||
|
Fluids
Division
|
$ | 20,791 | $ | 5,401 | $ | 10,897 | ||||||
|
Offshore
Division
|
||||||||||||
|
Offshore
Services
|
78,394 | 3,019 | 33,496 | |||||||||
|
Maritech
|
22,012 | (31,932 | ) | (49,815 | ) | |||||||
|
Intersegment
eliminations
|
647 | (782 | ) | 6,225 | ||||||||
|
Total
|
101,053 | (29,695 | ) | (10,094 | ) | |||||||
|
Production
Enhancement Division
|
||||||||||||
|
Production
Testing
|
17,690 | 35,677 | 25,639 | |||||||||
|
Compressco
|
23,563 | 30,310 | 26,663 | |||||||||
|
Total
|
41,253 | 65,987 | 52,302 | |||||||||
|
Corporate
overhead
|
(57,727 | ) | (45,608 | ) | (50,943 | ) | ||||||
| 105,370 | (3,915 | ) | 2,162 | |||||||||
2009
Compared to 2008
Consolidated
Comparisons
Revenues and Gross Profit –
Our total consolidated revenues for 2009 were $878.9 million compared to
$1,009.1 million for the prior year, a decrease of 12.9%. Total consolidated
gross profit increased to $213.1 million during 2009 compared to $152.0 million
in the prior year, an increase of 40.2%. Consolidated gross profit as a
percentage of revenue was 24.2% during 2009 compared to 15.1% during the prior
year. See the
Divisional
Comparisons
section below for a discussion of the changes in consolidated
revenues and gross profit during 2009 compared to 2008.
General and Administrative Expenses
–
General and administrative expenses were $100.8 million during 2009
compared to $104.9 million during 2008, a decrease of $4.1 million or 3.9%. This
decrease was primarily due to approximately $2.2 million of decreased salary,
benefits, contract labor costs, and other associated employee expenses,
primarily due to overall personnel cost reduction efforts. This decrease was
despite increased incentive bonus and equity compensation expenses. General and
administrative expenses were also decreased due to approximately $2.1 million of
decreased office expense, primarily from decreased office rent following the
first quarter 2009 relocation to our new corporate headquarters building,
approximately $0.8 million of decreased professional fees, and approximately
$0.6 million of decreased marketing, investor relations, and other general
expenses. These decreases were partially offset by approximately $1.3 million of
increased insurance and property tax expenses and approximately $0.3 million of
increased bad debt expenses. Despite these net decreases, general and
administrative expenses as a percentage of revenue increased to 11.5% during
2009 compared to 10.4% during the prior year due to decreased
revenues.
Other Income and Expense –
Other income and expense was $5.9 million of income during 2009 compared
to $12.9 million of income during the prior year, primarily due to the change in
hedge ineffectiveness, as we recognized approximately $1.7 million of hedge
ineffectiveness losses during the
current year
compared to $8.6 million of hedge ineffectiveness gains during the prior year.
In addition, earnings from unconsolidated joint ventures decreased $5.7 million,
primarily due to an impairment charge of approximately $6.6 million during 2009
associated with the write down of our unconsolidated European joint venture
investment. Partially offsetting these decreases, we recorded $4.6 million of
increased net legal settlement income, $4.0 million of increased gains on sales
of assets, and $0.4 million of increased foreign currency gains during
2009.
Interest Expense and Income Taxes –
Net interest expense decreased to $12.8 million during 2009 compared to
$16.8 million during 2008, despite increased borrowings of long-term debt during
much of the year, which were used to fund our 2009 capital expenditure and
working capital requirements. The decrease was primarily due to $3.6 million of
increased capitalized interest primarily associated with our Arkansas calcium
chloride plant and corporate headquarters construction projects. The corporate
headquarters building was completed during the first quarter of 2009, and our
new calcium chloride facility in El Dorado, Arkansas, began initial production
during the fourth quarter of 2009. Accordingly, despite a decrease in the
balance of
40
long-term debt
outstanding as of December 31, 2009, our net interest expense is expected to
increase beginning in 2010 since the amount of interest capitalized will be
reduced. Our provision for income taxes during 2009 increased to $36.6 million
compared to $5.7 million during the prior year, primarily due to increased
earnings.
Net Income –
Net income
before discontinued operations was $68.8 million during 2009 compared to a net
loss before discontinued operations of $9.7 million in the prior year, an
increase of $78.5 million. Net income per diluted share before discontinued
operations was $0.91 on 75,721,651 average diluted shares outstanding during
2009 compared to a net loss per diluted share before discontinued operations of
$0.13 on 74,519,371 average diluted shares outstanding in the prior
year.
During the fourth
quarter of 2007, we sold our process services operation for approximately $58.7
million, net of certain adjustments. During the fourth quarter of 2006, we made
the decision to discontinue our Venezuelan fluids and production testing
businesses due to several factors, including the changing political climate in
that country. Net loss from discontinued operations was $0.0 million during 2009
compared to $2.5 million of net loss from discontinued operations during
2008.
Net income was
$68.8 million during 2009 compared to a net loss of $12.1 million in the prior
year, an increase of $80.9 million. Net income per diluted share was $0.91 on
75,721,651 average diluted shares outstanding during 2009 compared to a net loss
per diluted share of $0.16 on 74,519,371 average diluted shares outstanding in
the prior year.
Divisional
Comparisons
Fluids Division –
Our Fluids
Division revenues during 2009 were $225.5 million, a decrease of $67.7 million
compared to $293.2 million of revenues during the prior year. This 23.1%
decrease was primarily due to a $59.6 million decrease in product sales
revenues, primarily due to decreased sales volumes of completion fluids as a
result of the overall decreased demand for the Division’s brine products. This
decrease reflects the overall decreased industry spending as reflected in the
U.S. and international rig counts during 2009 compared to 2008 and the current
trend of many operators to defer completion operations on drilled oil and gas
wells. In addition, the decreased product sales revenues were due to decreased
sales volumes of the Division’s manufactured chemicals products, primarily due
to the impact of decreased economic conditions which have affected the level of
activity of the Division’s oil and gas industry customers. The Division also
reflected $8.1 million of decreased service revenues, primarily due to decreased
U.S. onshore oil and gas activity. During the fourth quarter of 2009, the
Division began initial production of liquid calcium chloride from its El Dorado,
Arkansas, plant facility. The plant also began initial production of dry calcium
chloride in early 2010. The Division expects that the new facility, along with a
general improvement in economic conditions, will contribute to increased
revenues beginning in 2010.
Our Fluids Division
gross profit decreased to $47.5 million during 2009 compared to $56.4 million
during the prior year, a decrease of $8.9 million or 15.8%. The decrease in
Division gross profit was primarily due to the decreased sales volumes discussed
above, particularly for U.S. completion fluids products. In addition, the Fluids
Division recorded approximately $1.4 million of impairments of long-lived assets
during 2009. Gross profit as a percentage of revenue increased, however, to
21.1% during 2009 compared to 19.2% during 2008, primarily due to increased
international margins, particularly by the Division’s European calcium
chloride operation.
As discussed above, the Division’s new El Dorado, Arkansas, calcium chloride
plant facility began initial production during the fourth quarter of 2009. The
Division expects that the new plant will result in reduced product costs and
increased profitability in the future, particularly once the plant begins to
produce at full capacity. Such benefits are expected despite increased raw
material costs following the 2009 renegotiation of certain terms of our supply
contracts with Chemtura Corporation (Chemtura) pursuant to Chemtura’s bankruptcy
proceedings during the past year.
Fluids Division
income before taxes during 2009 totaled $20.8 million compared to $5.4 million
during the prior year, an increase of $15.4 million or 284.9%. This increase was
primarily due to a non-recurring $23.9 million charge for the impairment of
goodwill recorded during the fourth quarter of 2008. This increase was partially
offset by the $8.9 million decrease in gross profit discussed above and a $6.6
million charge during 2009 associated with the impairment of the Division’s
investment in a European unconsolidated joint venture. The joint venture ceased
operation of the calcium chloride manufacturing plant following our joint
venture partner’s announced closure of its adjacent plant facility which
supplies the joint venture’s plant with
41
feedstock raw
material. These decreases in earnings were partially offset by approximately
$6.2 million of decreased administrative expenses and approximately $0.9 million
of increased other income, which was primarily due to a $1.4 million charge for
a legal settlement in the prior year period.
Offshore Division –
Revenues
from our Offshore Division decreased from $491.9 million during 2008 to $485.2
million during 2009, a decrease of $6.7 million or 1.4%. Offshore Division gross
profit during 2009 totaled $115.7 million compared to $12.3 million during the
prior year, an increase of $103.4 million or 841.9%. Offshore Division income
before taxes was $101.1 million during 2009 compared to a loss before taxes of
$29.7 million during the prior year, an increase of $130.7 million.
The revenues of the
Division’s Offshore Services operations increased to $353.8 million during 2009
compared to $306.4 million during the prior year, an increase of $47.4 million
or 15.5%. This increase was due to increased utilization, particularly by the
segment’s diving, abandonment, heavy lift, and cutting services businesses,
which enjoyed unprecedented high demand following the 2005 and 2008 hurricanes.
Beginning in June 2009, the segment increased its service fleet through the
leasing of a specialized dive service vessel which was utilized for contracted
hurricane recovery work during the remainder of the year and is expected to be
utilized in early 2010. Following the current winter season, the Offshore
Services segment plans to continue to capitalize on the anticipated high demand
levels for well abandonment and decommissioning services in the Gulf of Mexico
to be performed over the next several years on offshore properties which were
damaged or destroyed by hurricanes. In addition, many offshore oil and gas
operators, including Maritech, have accelerated their efforts to abandon and
decommission offshore platform facilities in response to the risks from future
storms and the significantly increased windstorm insurance cost for offshore
properties. Many of such operators have discontinued or reduced their windstorm
insurance coverage until premium costs decrease or become justifiable and are
seeking to maximize their abandonment and decommissioning activity in order to
decrease their risk of future damage. A significant amount of such work is
planned for Maritech during 2010.
The Offshore
Services segment of the Division reported gross profit of $94.5 million during
2009 compared to $43.0 million of gross profit during 2008, a $51.5 million or
119.6% increase. The Offshore Services segment’s gross profit as a percentage of
revenues was 26.7% during 2009 compared to 14.0% during the prior year. This
increase was primarily due to the increased gross profit of the segment’s heavy
lift, diving, and cutting services businesses, which generated significant
efficiencies from increased utilization during 2009. These efficiencies were
partially due to improved weather conditions during the current year period, as
the segment incurred significant downtime during the third quarter of 2008 due
to Hurricanes Gustav and Ike. The hurricane season from June through November
can generate significant downtime in certain years. In addition, heavy seas,
winds and winter squalls tend to disrupt activities and, therefore, reduce
demand for our services in the first and fourth quarters. Also, during 2008 the
Offshore Services segment recorded an $8.7 million impairment of certain
long-lived assets. In addition, during 2009 the segment consolidated certain
office and administrative functions, reduced crews, and sold or temporarily
idled selected inland water equipment in order to increase efficiencies for
certain of its operations.
Offshore Services
segment income before taxes increased from $3.0 million during 2008 to $78.4
million during 2009, an increase of $75.4 million or 2,496.9%. This increase was
due to the $51.5 million increase in gross profit described above, and $2.5
million of decreased administrative expenses, partially offset by approximately
$1.8 million of increased other expense, primarily due to a legal settlement
during the
third quarter of
2009. In addition, the Offshore Services segment recorded a charge to earnings
of $23.2 million for a goodwill impairment during the fourth quarter of
2008.
The Division’s
Maritech operations reported revenues of $177.0 million during 2009 compared to
$208.5 million during the prior year, a decrease of $31.5 million or 15.1%.
Decreased realized commodity prices resulted in $17.7 million of decreased
revenues, as during 2009 Maritech reflected average realized oil and natural gas
prices of $65.13/barrel and $8.41/MMBtu, respectively, each of which was lower
than 2008 levels. Realized oil and natural gas prices during the first quarter
of 2010 have increased, however, compared to the average prices received during
2009. Maritech has hedged a portion of its expected future production levels by
entering into derivative hedge contracts. The average realized prices above
include the impact of these hedge contracts during 2009, which significantly
reduced the impact of decreased prices during the year. In addition to decreased
pricing, decreased Maritech production volumes resulted in decreased revenues of
approximately $15.3 million primarily due to one of Maritech’s key oil producing
fields, the East Cameron 328 field, being shut-in for most of the year. Maritech
has restored the majority of the storm-
42
interrupted
production from East Cameron 328, but will continue to have a portion of its
production shut-in until a new platform can be constructed to replace a platform
which was toppled during Hurricane Ike. During the fourth quarter of 2009,
Maritech installed additional production equipment on the remaining platform in
the field in order to restore a portion of the field’s production. The decreased
production from normal production declines and the shut-in properties more than
offset newly added production during the period from wells drilled in 2008 and
2009. The level of Maritech’s drilling and development activity has decreased
during 2009 as a result of our efforts to conserve capital. Partially offsetting
the revenue decreases associated with decreased pricing and production volumes,
Maritech reported $1.5 million of increased processing revenue during the
current year period.
Maritech reported
gross profit of $20.7 million during 2009 compared to negative gross profit of
$30.0 million during 2008, an increase of $50.6 million. This increase was
despite the $31.5 million decrease in revenue discussed above. Maritech’s gross
profit as a percentage of revenues during 2009 was 11.7%. This increase in gross
profit was primarily due to the $44.7 million of increased insurance related
gains, primarily from the $40 million settlement of our insurance litigation
regarding claims associated with damage from Hurricanes Katrina and Rita. The
proceeds from this settlement were received during the fourth quarter of 2009.
In addition, Maritech recorded oil and gas property impairments of $11.4 million
during 2009, compared to $42.6 million during 2008. Also, Maritech recorded
$13.8 million of decreased operating expenses and depreciation, depletion, and
amortization during 2009 compared to the prior year. This decrease was primarily
due to decreased production volumes and reduced insurance premium costs,
following Maritech’s decision to self insure from windstorm damage risk during
the last half of the year. Maritech also recorded $9.1 million of dry hole costs
during 2008. Partially offsetting these expense decreases, Maritech recorded
$16.7 million of increased excess decommissioning costs incurred during
2009.
Maritech reported
income before taxes of $22.0 million during 2009, compared to a pretax loss of
$31.9 million during 2008, an increase of $53.9 million. This increase was due
to the $50.6 million increase in gross profit discussed above, approximately
$2.9 million of increased gains on sales of properties recorded, and
approximately $0.7 million of decreased administrative costs, partially offset
by approximately $0.3 million of decreased other income during 2009 compared to
the prior year.
Production Enhancement Division –
Production Enhancement Division revenues decreased from $224.4 million
during 2008 to $168.7 million during 2009, a decrease of $55.8 million or 24.9%.
Production Enhancement Division gross profit decreased from $85.7 million during
2008 to $52.9 million during 2009, a decrease of $32.9 million or 38.4%.
Production Enhancement Division gross profit as a percentage of revenue also
decreased from 38.2% during 2008 to 31.3% during 2009. Production Enhancement
Division income before taxes decreased during 2009 to $41.3 million compared to
$66.0 million during 2008, a decrease of $24.7 million or 37.5%.
Production Testing
revenues decreased significantly during 2009 to $80.6 million, a 36.6% or $46.5
million decrease compared to $127.0 million during 2008. This decrease was due
to the decrease in U.S. operations, primarily from reduced drilling activity as
reflected by the U.S. rig count. The decreased demand has also resulted in
decreased day rates for our services. The Division’s Production Testing segment
is particularly affected by the activities of its U.S. customers, many of which
have been significantly affected by the current economic climate. This decrease
was partially offset by increased international revenues, primarily in Mexico
and Brazil.
Production Testing
gross profit also decreased from $44.4 million during 2008 to $19.2 million
during 2009, a decrease of $25.2 million or 56.9%. Gross profit as a percentage
of revenues also decreased from 35.0% during 2008 to 23.8% during 2009. This
decrease in gross profit was due to the weaker demand, lower day rates, and
decreased activity in the U.S.
Production Testing
income before taxes decreased from $35.7 million during 2008 to $17.7 million
during 2009, a decrease of $18.0 million or 50.4%. This decrease was due to the
$25.2 million decrease in gross profit discussed above, which was partially
offset by approximately $7.1 million of increased other income, primarily due to
a $5.6 million legal settlement gain, $0.5 million of increased gains on sales
of assets, and $1.0 million of increased other income, primarily from increased
earnings from an unconsolidated joint venture.
43
Compressco revenues
during 2009 decreased to $88.1 million during 2009 compared to $97.4 million
during 2008, a decrease of $9.3 million and 9.6%, reflecting the decreased U.S.
demand during most of 2009 compared to the prior year. Lower natural gas prices
compared to the prior year and general industry economic conditions have
resulted in decreased demand for wellhead compression services, as reflected in
Compressco’s reduced utilization of its GasJack
®
compressor fleet. In response to the current economic environment, beginning in
early 2009, Compressco has slowed its fabrication of new compressor units until
demand for its production enhancement services increases and inventories of
available units are reduced. However, Compressco continues to seek new niche
opportunities to expand its operations, including additional opportunities in
international markets.
Compressco gross
profit decreased from $41.3 million during 2008 to $33.7 million during 2009, a
decrease of $7.6 million or 18.5%. Gross profit as a percentage of revenues also
decreased from 42.4% during 2008 to 38.2% during 2009. This decrease in gross
profit was primarily due to unabsorbed fabrication overhead as a result of the
decreased production of new compressor units along with other increased
operating expenses for Compressco’s U.S. operations.
Income before taxes
for Compressco decreased from $30.3 million during 2008 to $23.6 million during
2009, a decrease of $6.7 million or 22.3%. This decrease was primarily due to
the $7.6 million of decreased gross profit discussed above, partially offset by
approximately $0.7 million of decreased administrative costs and $0.2 million of
increased other income.
Corporate Overhead –
Corporate Overhead includes corporate general and administrative expense,
interest income and expense, and other income and expense. Such expenses and
income are not allocated to our operating divisions, as they relate to our
general corporate activities. Corporate Overhead increased from $45.6 million
during 2008 to $57.7 million during 2009, primarily due to increased
administrative expense, depreciation and other expense. Corporate administrative
costs increased approximately $6.0 million, primarily due to approximately $6.9
million of increased salary and employee expenses. Although Corporate employee
salary expenses decreased due to cost reduction efforts, these decreases were
more than offset by increases in company-wide incentive bonus and equity
compensation expense. In addition, Corporate administrative expenses increased
due to approximately $1.0 million of increased insurance, taxes, and other
general expenses. These administrative cost increases were partially offset by
$1.0 million of decreased professional services and investor relations expense
and $0.9 million of decreased office expenses, primarily from decreased office
rent following the first quarter 2009 relocation to our new corporate
headquarters building. In addition to increased administrative expenses,
Corporate Overhead expense increased due to a $9.7 million change in other
income (expense) during 2009 compared to 2008. This increase was primarily due
to $1.7 million of hedge ineffectiveness losses included in other expense during
2009 compared to $8.6 million of hedge ineffectiveness gains which were included
in other income during 2008. In addition, Corporate Overhead expense increased
due to $0.6 million of increased depreciation expense, primarily due to our new
corporate headquarters building. Partially offsetting these increases, Corporate
interest expense decreased by approximately $4.1 million during 2009 primarily
due to an increase in the amount of interest capitalized on construction
projects during the period.
2008
Compared to 2007
Consolidated
Comparisons
Revenues and Gross Profit –
Total consolidated revenues for the year ended December 31, 2008 were
$1,009.1 million compared to $982.5 million for the prior year, an increase of
2.7%. Consolidated gross profit increased to $152.0 million during 2008 compared
to $116.4 million in the prior year, an increase of 30.6%. Consolidated gross
profit as a percentage of revenue was 15.1% during 2008 compared to 11.8% during
the prior year period. Our profitability during 2008 and 2007 was significantly
affected by several factors, which are discussed in detail in the
Divisional Comparisons
section below.
General and Administrative Expenses
–
General and administrative expenses were $104.9 million during 2008
compared to $99.9 million during the prior year, an increase of $5.1 million or
5.1%. This increase was primarily due to $1.5 million of increased legal and
professional services fees, $1.6 million of increased bad debt expenses, $0.2
million of increased office expenses, and $1.7 million of other increased
general expenses. Despite approximately $1.5 million of increased option
expense, total personnel costs increased only approximately $0.1 million, due to
decreased salaries, insurance, and other employee related
44
expenses. General
and administrative expenses as a percentage of revenue were 10.4% during 2008
compared to 10.2% during the prior year.
Impairment of Goodwill –
During the fourth quarter of 2008, changes to the global economic environment
resulting in uncertain capital markets and reductions in global economic
activity had a severe adverse impact on stock markets and oil and natural gas
prices, both of which contributed to a significant decline in our company’s
stock price and corresponding market capitalization. As part of our annual test
of goodwill impairment, we estimated the fair value of each of our reporting
units, and determined, based on these estimated values, that an impairment of
the goodwill of our Fluids and Offshore Services reporting units was necessary,
primarily due to the market factors discussed above. Accordingly, during the
fourth quarter of 2008, we recorded total impairment charges of $47.1 million
associated with the goodwill impairment for these
segments.
Other Income and Expense –
Other income and expense was $12.9 million of income during 2008 compared
to $2.8 million of income during 2007, primarily due to approximately $8.5
million of increased ineffectiveness gains from liquidated commodity
derivatives, $1.6 million of increased equity from earnings of unconsolidated
joint ventures, $1.4 million of increased currency exchange gains, and $0.9
million from increased gains from sales of long-lived assets. These increases
were partially offset by approximately $2.3 million of decreased other income,
primarily due to a $1.4 million legal settlement expensed during the current
year and a $1.2 million legal settlement credited to earnings during
2007.
Interest Expense and Income Taxes –
Net interest expense decreased from $17.2 million during 2007 to $16.8
million during the current year. This decrease occurred despite the increased
borrowings of long-term debt used to fund our capital expenditure and
acquisition requirements during 2007 and 2008 and was due to lower interest
rates during the period as well as due to increased interest capitalized
associated with our capital construction projects. Interest expense will
increase in future periods as these capital construction projects are completed
and to the extent additional borrowings are used to fund our acquisition and
capital expenditure plans. Our provision for income taxes during 2008 increased
to $5.7 million compared to $0.9 million during the prior year, primarily due to
the increased effective state tax rate for certain of our operations and the
nondeductible nature of a portion of our goodwill impairments during
2008.
Net Income (Loss) –
Net loss
before discontinued operations was $9.7 million during 2008 compared to net
income of $1.2 million in 2007, a decrease of $10.9 million. Net loss per
diluted share before discontinued operations was $0.13 on 74,519,371 average
diluted shares outstanding during 2008 compared to net income per diluted share
before discontinued operations of $0.02 on 75,920,768 average diluted shares
outstanding during the prior year.
During the fourth
quarter of 2007, we sold our process services operation for approximately $58.7
million, net of certain adjustments, as this operation was not a strategic part
of our core operations. In addition, during the fourth quarter of 2006, we made
the decision to discontinue our Venezuelan fluids and production testing
businesses due to several factors, including the changing political climate in
that country. Loss from discontinued operations was $2.5 million during 2008
compared to income from discontinued
operations of $27.6
million during 2007, primarily due to the $25.8 million after tax gain on the
sale of the process services operations during the prior year.
Net loss was $12.1
million during 2008 compared to net income of $28.8 million in 2007, a decrease
of $40.9 million. Net loss per diluted share was $0.16 on 74,519,371 average
diluted shares outstanding during 2008 compared to $0.38 of net income per
diluted share on 75,920,768 average diluted shares outstanding in the prior
year.
Divisional
Comparisons
Fluids Division –
Fluids
Division revenues during 2008 were $293.2 million, compared to $282.1 million
during 2007, an increase of $11.2 million or 4.0%. This increase was primarily
due to $14.0 million of increased revenues from the sales of manufactured
products, particularly in Europe, primarily resulting from increased pricing. In
addition, the Division reported $11.2 million of increased service revenues
primarily due to increased U.S. onshore service activity as well as the April
2007 acquisition of the assets and operations of a company providing fluids
transfer and related services in support of high pressure fracturing processes.
These increases were partially offset by decreased brine sales revenues, which
declined $14.1 million due to
45
decreased sales
volumes and prices, particularly during the last half of 2008, as many operators
were recovering from the third quarter 2008 hurricanes. A large portion of the
demand for the Division’s products and services is affected by the level of
drilling activity, including deepwater drilling, particularly in the Gulf of
Mexico region. This decrease in brine sales, particularly U.S. offshore, is
expected to continue during 2009 as operators continue to recover from the
storms and as overall spending in the oil and gas industry remains decreased due
to the current economic uncertainty. However, during 2008, we entered into a
long-term contract with Petrobras to provide completion fluids for its deepwater
drilling program offshore Brazil, which should contribute added revenues in
future years.
Our Fluids Division
gross profit increased to $56.4 million during 2008, compared to $38.6 million
during the prior year, an increase of $17.8 million or 46.2%. Gross profit as a
percentage of revenue increased to 19.2% during 2008 compared to 13.7% during
the prior year. This increase in gross profit was primarily due to the increased
service activity discussed above. In addition, rainy weather conditions during
much of 2007 negatively impacted the Division’s onshore and completion services
operations. The increased raw material costs for certain of our manufactured
products were largely offset by decreased brine costs. A favorable long-term
supply for certain of the Division’s raw material needs has been secured, and
the Division has begun to reflect lower product costs as a result. In December
2007, the Division terminated its remaining purchase commitment under its
previous supply agreement in consideration of its agreement to pay $9.3 million,
which was charged to operations during the fourth quarter of 2007.
Fluids Division
income before taxes during 2008 totaled $5.4 million compared to $10.9 million
in the prior year, a decrease of $5.5 million or 50.4%. This decrease was due to
an impairment of the Division’s goodwill for $23.9 million during the fourth
quarter of 2008, which more than offset the $17.8 million increase in gross
profit discussed above. In addition, the Division reported approximately $0.1
million of decreased administrative expenses and approximately $0.4 million of
increased other income, as a $1.4 million charge for a legal settlement and $0.6
million of decreased gains on asset sales were more than offset by $1.5 million
of increased foreign currency gains and $0.9 million of increased earnings from
unconsolidated joint ventures.
Offshore Division –
The
revenues of our Offshore Division decreased from $526.2 million during 2007 to
$491.9 million during 2008, a decrease of $34.3 million or 6.5%. Offshore
Division gross profit during 2008 totaled $12.3 million compared to $9.7 million
during 2007, an increase of $2.6 million or 26.6%. Offshore Division loss before
taxes was $29.7 million during 2008 compared to a $10.1 million loss before
taxes during the prior year, a decrease of $19.6 million.
The Division’s
Offshore Services operations revenues decreased by 10.2% to $306.4 million
during 2008 compared to $341.1 million in the prior year, a decrease of $34.7
million. Excluding intercompany work performed for Maritech, Offshore Services
revenues decreased by $28.6 million, or 9.2%. Decreased heavy lift capacity as
compared to the prior year resulted in approximately $52.7 million of decreased
segment revenue, as the Offshore Services segment had two additional leased
vessels operating during a portion of 2007. In addition, the Division’s
operations were plagued by poor weather throughout much of 2008 due to three
named storms in addition to Hurricanes Gustav and Ike, resulting in disruptions
to the Division’s planned activities. These decreases were partially offset by
increased diving and cutting services, which have
particularly
increased following the hurricanes which occurred during the third quarter of
2008. The Division aims to capitalize on the current and expected demand for
well abandonment, decommissioning, diving, and other service activity in the
Gulf of Mexico, including the work to be performed over the next several years
on offshore properties that were damaged or destroyed by hurricanes in 2005 and
2008.
The Offshore
Services segment of the Division reported gross profit of $43.0 million during
2008, a $6.1 million decrease compared to $49.1 million during 2007. Offshore
Services gross profit as a percentage of revenues also decreased to 14.0% during
2008 compared to 14.4% during 2007. The 12.4% decrease in gross profit was
primarily due to the $8.7 million impairment of certain long-lived assets during
2008. In addition, the segment experienced significant decreases in abandonment
and decommissioning activity as a result of the reduced heavy lift capacity and
weather disruptions throughout the year. Weather resulted in a postponement of
several projects throughout the year, resulting in reduced efficiency and profit
for these projects. These decreases more than offset the operating efficiencies
of our dive services business, which generated significant efficiencies from
high utilization, particularly following the third quarter 2008 hurricanes. In
addition, during 2007 the Offshore Services segment charged approximately $2.0
million to operations related to a contested insurance claim. Intercompany
profit on work performed for Maritech’s insured storm damage repairs is not
recognized until such time as the associated insurance claim proceeds are
collected by
46
Maritech. During
2007, insurance claim collections related to intercompany work performed in 2006
for Maritech contributed to the recognition of an additional $6.2 million of
Division intercompany gross profit.
The Offshore
Services segment’s income before taxes decreased from $33.5 million during 2007
to $3.0 million during 2008, a decrease of $30.5 million or 91.0%. This decrease
was due to the $6.1 million decrease in gross profit described above and due to
a $23.2 million charge for goodwill impairment during the fourth quarter of
2008. In addition, other income decreased by approximately $1.5 million,
primarily due to a legal settlement received during the prior year. These
decreases were partially offset by a $0.3 million decrease in administrative
expenses.
The Division’s
Maritech operations reported revenues of $208.5 million during 2008 compared to
$214.2 million during 2007, a decrease of $5.6 million, or 2.6%. As a result of
Hurricane Ike during the third quarter of 2008, Maritech suffered damage to many
of its offshore production platforms and third-party pipelines and facilities,
which caused many of its producing properties to be shut-in during much of the
last four months of 2008. Three offshore platforms and one inland water
production facility were destroyed by Hurricane Ike, one of which served a key
producing field. These destroyed platforms are in addition to the three offshore
platforms destroyed by hurricanes during 2005. Much of Maritech’s daily
production is processed through neighboring platforms, pipelines, and processing
facilities of other operators and third parties, many of which were also damaged
during the storm. As a result, a portion of Maritech’s production remains
shut-in. Due primarily to the impact of these storms and despite increased gas
production as a result of successful exploitation and development activities and
from the acquisitions of properties over the past two years, overall equivalent
barrel production volumes decreased during 2008 compared to the prior year,
resulting in $23.7 million of decreased revenues. This decrease was largely
offset by $17.6 million of increased revenue from higher oil and natural gas
prices for much of 2008 compared to the prior year. However, beginning in the
third quarter of 2008 and continuing into 2009, oil and natural gas prices have
declined significantly. Maritech has hedged a portion of its expected future
production levels by entering into derivative hedge contracts, with certain
contracts extending through 2010. In addition to the impact from decreased
production volumes and increased prices, Maritech revenues also increased $0.5
million during 2008 compared to the prior year, due to increased platform
processing revenues. The full resumption of Maritech’s pre-storm production
levels may never occur and will depend on the extent of damage and the repairs
or reconstruction needed on certain assets. In addition, while Maritech plans to
continue to replace its depleting oil and gas reserves through development
activities, the amount of such expenditures must now be evaluated more
critically in light of the current lower price environment and our need to
conserve capital.
The Division’s
Maritech operations reported a negative gross profit of $30.0 million during
2008 compared to $45.6 million of negative gross profit during 2007, a decrease
in the amount of loss of $15.7 million or 34.3%. Maritech’s gross profit as a
percentage of revenues increased during the current year to a negative 14.4%
compared to a negative 21.3% during the prior year. This increase occurred
despite the segment’s decrease in revenues during the current year, due to the
decreased amount of oil and gas property impairments during 2008 compared to
2007. Maritech recorded $76.1 million of impairments during 2007, primarily due
to the reversal of anticipated insurance recoveries as a result of certain
future well intervention
and debris removal
costs being contested by our insurance provider. This decrease in anticipated
insurance recoveries further reduced Maritech’s gross profit associated with
certain hurricane damage repair costs incurred and resulted in a $13.5 million
charge to operating expense, as the timing and amount of the reimbursement of
these costs had become indeterminable. During the fourth quarter of 2007,
Maritech filed a lawsuit against certain of its insurance underwriters related
to certain contested well intervention and debris removal costs incurred and to
be incurred on three offshore platforms which were destroyed by 2005 hurricanes.
During the third and fourth quarters of 2008, Maritech recorded a total of $42.7
million of oil and gas property impairments, primarily due to decreasing oil and
natural gas prices. In addition, Maritech’s gross profit increased during 2008
due to $5.1 million of decreased excess decommissioning and abandoning costs.
The increased gross profit was partially offset by $10.7 million of increased
depreciation and depletion expense and $7.4 million of increased dry hole costs.
In addition, Maritech’s insurance costs decreased by $1.2 million during 2008
compared to 2007.
The Division’s
Maritech operations reported a loss before taxes of $31.9 million during 2008
compared to a $49.8 million loss before taxes during the prior year, a $17.9
million decrease in the amount of loss. This 35.9% decrease was due to the $15.7
million decrease in negative gross profit and approximately $2.2 million of
increased other income, primarily due to gains on sales of properties, partially
offset by $0.1 million of increased administrative costs compared to the prior
year.
47
Production Enhancement Division
–
Production Enhancement Division revenues increased significantly from
$176.7 million during 2007 to $224.4 million during 2008, an increase of $47.8
million or 27.0%. Production Enhancement Division gross profit during 2008
totaled $85.7 million compared to $69.5 million during the prior year, an
increase of $16.2 million or 23.4%. Production Enhancement Division income
before taxes was $66.0 million during 2008 compared to $52.3 million of income
before taxes during the prior year, an increase of $13.7 million or
26.2%.
Production Testing
segment revenues increased from $93.1 million during 2007 to $127.0 million
during 2008, an increase of $33.9 million or 36.4%. This increase was primarily
due to $18.9 million of revenues from increased U.S. demand, where activity
levels were high throughout 2008 despite decreased oil and natural gas pricing
during the last portion of the year. Approximately $15.5 million of the
increased Production Testing revenues were also attributed to increased activity
in Mexico and Brazil. These increases were partially offset by $0.5 million of
decreased environmental service fees compared to the prior year.
Production Testing
gross profit increased $11.6 million during 2008 compared to 2007, increasing
from $32.8 million to $44.4 million during 2008, an increase of 35.4%. Gross
profit as a percentage of revenue decreased slightly, however, from 35.2% during
2007 to 35.0% during 2008. The increased gross profit reflected the higher level
of activity throughout 2008, particularly for the segment’s international
operations.
Production Testing
reported income before taxes of $35.7 million during 2008, compared to $25.6
million during 2007, an increase of $10.0 million or 39.2%. This increase was
due to the increased gross profit discussed above and $0.4 million of decreased
other expense, primarily due to decreased foreign currency losses. These
increases were partially offset by approximately $2.0 million of increased
administrative costs.
The Division’s
Compressco segment revenues increased by approximately $13.9 million during 2008
compared to the prior year, increasing 16.6% from $83.6 million during 2007 to
$97.4 million during 2008. The majority of this increase occurred in the United
States, however, Compressco’s operations in Mexico also increased significantly
compared to the prior year. Compressco continued to add to its compressor fleet
throughout 2008 to meet the growing demand for its services.
Compressco’s gross
profit increased from $36.7 million during 2007 to $41.3 million during 2008, an
increase of $4.6 million or 12.6%, primarily due to increased activity. Gross
profit as a percentage of revenues decreased, however, from 43.9% during 2007 to
42.4% during 2008, primarily due to increased operating costs for its U.S.
operations, despite increased strong margins on the growing Mexican
operations.
Income before taxes
for the Compressco segment increased from $26.7 million during 2007 to $30.3
million during 2008, an increase of $3.6 million or 13.7%. This increase was
primarily due to the $4.6 million of increased gross profit discussed above,
less approximately $0.8 million of increased administrative costs and $0.2
million of increased other expense.
Corporate Overhead –
Corporate Overhead includes corporate general and administrative
expenses, interest income and expense, and other income and expense. Such
expenses and income are not allocated to our operating divisions, as they relate
to our general corporate activities. Corporate overhead decreased by $5.3
million from $50.9 million during 2007 to $45.6 million during 2008 due to $8.6
million of increased other income, primarily from increased ineffectiveness
gains on liquidated derivative contracts, which resulted in $8.5 million of
other income. These gains were partially offset by approximately $2.7 million of
increased corporate administrative costs and $1.0 million of increased
depreciation expense. The increase in corporate administrative costs was
primarily from $1.4 million of increased personnel costs, primarily from
increased stock option expense, approximately $0.5 million of increased legal
and professional fees, and approximately $0.7 million of increased general
expenses. Net corporate interest expense decreased approximately $0.3 million
due to lower interest rates and additional amounts of interest capitalized
associated with our capital construction projects. The increased capitalization
of interest will continue until our significant capital construction projects
are completed, which is expected to occur later during 2009.
48
Liquidity
and Capital Resources
During the past
year, we have specifically focused on conserving capital resources, even while
completing the largest construction project in our history. This focus has been
accomplished by reducing or deferring other capital projects, reducing operating
and administrative costs, maximizing operating efficiencies, idling or disposing
of non-strategic assets, and carefully managing working capital. These efforts,
along with the strong performance of our Offshore Services segment during the
year, have more than overcome the decrease in revenues and operating cash flows
from many of our other businesses and have resulted in increased consolidated
operating cash flows during 2009 compared to 2008. Cash generated during the
year was used to pay the remaining outstanding balance of our bank revolving
credit facility and to increase our cash on hand as of yearend. We have
historically funded the majority of our capital expenditure requirements through
operating cash flows. We are continuing to conserve capital spending going
forward, as we monitor the operating cash flows of each of our businesses. While
focusing on these efforts, we also continue to seek opportunities for growth,
particularly internationally, either through strategic expansion of existing
businesses in niche markets or through suitable acquisitions. Our increased
liquidity and availability under our revolving credit facility, which is
scheduled to mature in June 2011, positions us to take advantage of growth
opportunities. During 2009, cash flows from operating activities increased to
$272.3 million, compared to $189.8 million during 2008, and funded $149.7
million of net investing activities, paid down $95.7 million of long-term debt
and other financing activities, and increased cash on hand by approximately
$29.5 million.
Operating Activities
– Cash
flow generated by operating activities grew to $272.3 million during 2009
compared to $189.8 million during 2008 and was primarily due to increased
earnings, collections of accounts receivable, and other working capital changes.
Contributing to the increased earnings was the operating results generated by
our Offshore Services segment and the fourth quarter 2009 collection of a $40.0
million Maritech insurance litigation settlement. In addition, during 2009 we
generated $23.1 million from the liquidation of certain oil swap derivative
contracts. The increase in operating cash flows occurred despite a significant
increase in the amount of Maritech decommissioning activity performed during
2009, and we plan to perform a similar level of decommissioning work in 2010.
Operating cash flows also increased despite the decreased demand for many of our
products and services, as cost reduction efforts and improved operating
efficiencies partially offset these decreases. For Maritech, the remaining
shut-in production resulting from damage suffered in 2008 from Hurricane Ike and
the reduction in drilling projects during the past year continue to negatively
affect the level of Maritech’s oil and gas production cash flows. In addition,
the oil and gas prices received for Maritech’s production were also decreased
compared to the prior year, although swap derivative hedge contracts partially
offset this decrease.
One of the most
significant uncertainties regarding the level of our operating cash flows in
2010 and beyond, in addition to the factors discussed below associated with our
Maritech operations, is the timing and magnitude of the continuing global
economic recovery and its impact on oil and gas industry activity. The demand
for a large portion of our products and services is driven by oil and gas
drilling and production activity generally. Our Production Testing and
Compressco segments, along with the completion fluids and services business of
our Fluids Division, have been particularly affected by the decrease in industry
activity during the past year, as reflected in the revenue and profitability
levels for these segments during 2009. Oil and gas prices and rig count activity
levels have been increasing during the last half of 2009 and during the first
portion of 2010. However, the overall demand for our products and services is
also driven by spending levels within the oil and
gas industry,
particularly domestically, which is also affected by the availability of capital
and general economic conditions. While we expect that the level of revenues and
cash flows for our Production Testing, Compressco, and Fluids segments will
improve modestly in 2010, such levels are expected to continue to be
significantly below the levels generated during the first half of
2008.
Our operating cash
flows continue to be affected by the impact from hurricanes. During 2008,
Hurricane Ike caused damage to certain of our properties, including damage to
many of Maritech’s offshore production platforms, three of which were destroyed.
Including the platforms and facility destroyed by Hurricanes Katrina and Rita
during 2005, one of which was decommissioned during 2009, Maritech has five
remaining destroyed platforms and associated wells on which it needs to perform
well intervention, abandonment, decommissioning, debris removal, platform
construction, and well redrilling. We estimate the cost to perform this
remaining work will be approximately $95 to $110 million. Approximately $70 to
$80 million of this amount has been accrued for as part of Maritech’s
decommissioning liability. Approximately $50 to $60 million of these amounts
relate to platforms destroyed by Hurricane Ike, and we anticipate that the
49
majority of these
costs will be reimbursed by insurance. See further discussion below. During
2009, we charged approximately $8.2 million of damage repair costs from
Hurricane Ike to earnings and as of December 31, 2009, we reflect an insurance
receivable of approximately $16.7 million for the portion of the costs incurred,
including non-hurricane related claims, that are covered by our various
insurance policies. Although a significant portion of the insurance
reimbursements associated with Hurricane Ike damage costs expended to
date was received during 2009 and early 2010, the timing of the collection
of additional reimbursements is beyond our control. Also related to Hurricane
Ike, one of the destroyed offshore platforms served the East Cameron 328 field,
which produced approximately 24.3% of our pre-storm oil production. During the
fourth quarter of 2009, Maritech modified one of the remaining platforms in this
field and has restored a portion of the interrupted production. The full
resumption of production from the East Cameron 328 field will require the
construction of a new platform and several wells to be redrilled, and these
efforts are estimated to cost approximately $25 to $30 million, before insurance
recoveries, and are not scheduled to be completed until 2011. Beginning in June
2009 and for the period ending May 2010, Maritech discontinued its insurance
coverage for windstorm damage due to the current high premium cost of insurance
and the reduced levels of coverage. This decision resulted in increased
operating cash flow during the last half of 2009 as a result of lower premium
costs. If Maritech elects to continue to self-insure for windstorm damage in
future periods, it will be exposed to losses from future uninsured windstorm
damages. Depending on the severity and location of the storms, such losses could
be significant.
Future operating
cash flow will also be affected by the timing and amount of expenditures
required for the plugging, abandonment, and decommissioning of Maritech’s oil
and gas properties. The third party discounted fair value, including an
estimated profit, of Maritech’s decommissioning liability as of December 31,
2009 totals $218.4 million ($234.0 million undiscounted). These amounts include
the well intervention, decommissioning, and debris removal efforts associated
with five remaining destroyed offshore platforms, including the three platforms
destroyed by Hurricane Ike. Approximately $77.9 million of the cash outflow
necessary to extinguish Maritech’s decommissioning liability is expected to
occur during 2010. The remainder of Maritech’s decommissioning liability is
expected to be extinguished in future years, as reserves are depleted.
The amount and timing of these cash outflows are estimated based on expected
costs, as well as on the timing of future oil and gas production and the
resulting depletion of Maritech’s oil and gas reserves. Such estimates are
imprecise and subject to change due to changing cost estimates, MMS
requirements, commodity prices, revisions of reserve estimates, and other
factors. The estimated cost to perform the work on the five remaining destroyed
platforms and associated wells is particularly imprecise due to the unique
nature of the work to be performed. Maritech’s decommissioning liability at
yearend includes $23.3 million of adjustments made during 2009 relating to
future work to be performed which were capitalized to the associated oil and gas
properties. Additional adjustments of approximately $23.8 million were primarily
related to work performed on certain properties during the year in excess of the
property’s decommissioning liability and were charged to earnings.
Maritech’s
estimated decommissioning liabilities are net of amounts allocable to joint
interest owners, contractual amounts to be paid by the previous owners of the
properties, and insurance recoveries. In some cases, the previous owners of
acquired properties are contractually obligated to pay Maritech a fixed amount
for the future well abandonment and decommissioning work on these properties as
the work is performed, partially offsetting Maritech’s future obligation
expenditures. Maritech’s decommissioning liability is net of approximately $43.6
million of amounts contractually required to be reimbursed to Maritech. Although
we anticipate that a majority of the well intervention, decommissioning, and
debris removal costs associated with
destroyed offshore
platforms from Hurricane Ike will be reimbursed by insurance, only costs that
are similar to the costs that were reimbursed by our insurers following
Hurricanes Katrina and Rita have been recognized as an insurance recovery
partially offsetting Maritech’s estimated decommissioning liabilities, and this
amount is approximately $10.3 million as of December 31, 2009. As of December
31, 2009, and prior to the impact of contractually required reimbursements and
insurance recoveries, Maritech’s total undiscounted decommissioning obligation
is approximately $287.9 million and consists of Maritech’s total liability of
$234.0 million, plus approximately $53.9 million of such future reimbursements
and recoveries.
Future operating
cash flow will continue to be affected by the oil and gas prices received for
Maritech’s production. To minimize the risk of fluctuating oil and gas prices,
Maritech enters into oil and natural gas swap derivative transactions that are
designated to hedge a portion of Maritech’s oil and gas production. Maritech’s
natural gas swap derivative contracts result in Maritech receiving a fixed price
for hedged natural gas production that is in excess of prices currently being
received. Although a majority of Maritech’s production is currently hedged,
these hedge contracts expire at the end of 2010.
50
Investing Activities
– During
2009, we expended approximately $151.8 million of cash for capital expenditures
and an additional $18.1 million on purchase consideration adjustments on
acquisition transactions from prior years. Approximately $65.9 million of the
2009 capital expenditures was spent on the construction of our new El Dorado,
Arkansas, calcium chloride plant facility, which began production of liquid
calcium chloride during the fourth quarter of 2009. The plant began production
of dry calcium chloride during the first quarter of 2010 and is expected to
begin sodium chloride production in 2011. The construction phase of the plant
was substantially complete as of December 31, 2009 at a total cost excluding
capitalized interest of approximately $126.9 million, making it the most
significant construction project in our history. During 2009, capital
expenditures associated with the El Dorado plant represented 43.4% of our total
capital expenditures, as many of our other investment projects were either
cancelled or deferred pending the completion of the plant. As a result, despite
the continuing plant construction costs during the year, our total cash capital
expenditures decreased by 42.1% compared to 2008. Going forward, our capital
expenditure plans will continue to be reviewed carefully in light of the current
capital market constraints and the continued reduced demand and operating cash
flows for several of our businesses.
During 2009, our
cash capital expenditures totaled approximately $151.8 million, $84.1 million of
which was expended by our Fluids Division, primarily for the construction of the
El Dorado plant facility, but also including improvements and expansion of
fluids and chemical plant facility locations. Our Offshore Division expended
approximately $44.3 million, consisting of approximately $26.8 million of
exploration and development expenditures for Maritech. In addition, the Offshore
Division also expended approximately $17.9 million for the Offshore Services
segment, primarily related to vessel and equipment refurbishments for its diving
and heavy lift operations. Our Production Enhancement Division spent
approximately $12.0 million, consisting of approximately $9.0 million to replace
and enhance a portion of the testing equipment fleet by our Production Testing
segment. In addition, Compressco spent approximately $2.9 million for general
infrastructure needs along with minimal expansion of its compressor fleet. Our
total capital expenditures also included approximately $11.4 million of
Corporate capital expenditures, primarily related to the final construction
phase of our new headquarters office building, which was completed in the first
quarter of 2009.
Generally, a
significant majority of our planned capital expenditures is related to
identified opportunities to grow and expand our existing businesses; however,
certain of these expenditures may be postponed or cancelled in our efforts to
conserve capital. We plan to expend over $140 million on total capital
expenditures during 2010, and while this represents a further decrease in total
capital expenditures compared to 2009, it would result in increased spending for
each of our business segments other than our Fluids Division. Many of our
capital expenditure plans will be deferred until activity levels increase.
Deferral of certain capital projects, such as the replacement or upgrading of
vessels in our Offshore Services fleet, could affect our ability to compete.
This restraint on capital expenditure activity may also affect future growth. In
particular, prior to 2009, we had invested significantly in Maritech acquisition
and development activities, and the current reduction in spending may result in
negative growth for Maritech over time as a result of postponing the replacement
of depleting oil and gas reserves and production cash flows. However, our
long-term growth strategy continues to include the pursuit of suitable
acquisitions. To the extent we consummate a significant acquisition, our
liquidity position will be affected.
Financing
Activities
To
fund our capital and working capital requirements, we may supplement our
existing cash balances and cash flow from operating activities as needed from
long-term borrowings, short-term borrowings, equity issuances, and other sources
of capital.
Bank Credit Facilities -
We
have a revolving credit facility with a syndicate of banks, pursuant to a credit
agreement which was amended in June 2006 and December 2006 (the Credit
Agreement). As of December 31, 2009 and February 26, 2010, we did not have any
outstanding balance on the revolving credit facility, and had $17.6 million in
letters of credit and guarantees against the $300 million revolving credit
facility, leaving a net availability of $282.4 million.
Pursuant to the
Credit Agreement, the revolving credit facility is scheduled to mature in June
2011, is unsecured, and is guaranteed by certain of our material U.S.
subsidiaries. Borrowings generally bear interest at the British Bankers
Association LIBOR rate plus 0.50% to 1.25%, depending on one of our financial
ratios. We pay a commitment fee ranging from 0.15% to 0.30% on unused portions
of the facility. The Credit Agreement contains customary covenants and other
restrictions, including certain financial ratio covenants involving our levels
of debt and interest cost compared to a defined measure of our operating cash
flow over a
51
twelve month
period. In addition, the Credit Agreement includes limitations on aggregate
asset sales, individual acquisitions, and aggregate annual acquisitions and
capital expenditures. Access to our revolving credit line is dependent upon our
ability to continue to comply with the certain financial ratio covenants set
forth in the Credit Agreement, as discussed above. Significant deterioration of
the financial ratios could result in a default under the Credit Agreement and,
if not remedied, could result in termination of the agreement and acceleration
of any outstanding balances under the facility prior to 2011. The Credit
Agreement also includes cross-default provisions relating to any other
indebtedness 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 Credit Agreement. Our Credit Agreement also contains a
covenant that restricts us from paying dividends in the event of a default or if
such payment would result in an event of default. We were in compliance with all
covenants and conditions of our Credit Agreement as of December 31, 2009. Our
continuing ability to comply with these financial covenants centers largely upon
our ability to generate adequate cash flow. Historically, our financial
performance has been more than adequate to meet these covenants, and subject to
the duration of the current economic environment, we expect this trend to
continue.
Senior Notes -
In September
2004, we issued, and sold through a private placement, $55.0 million in
aggregate principal amount of Series 2004-A Senior Notes and 28 million Euros
(approximately $40.1 million equivalent at December 31, 2009) in aggregate
principal amount of Series 2004-B Senior Notes pursuant to a Master Note
Purchase Agreement. The Series 2004-A Senior Notes and 2004-B Senior Notes were
sold in the United States to accredited investors pursuant to an exemption from
the Securities Act of 1933. Net proceeds from the sale of the Senior Notes were
used to pay down a portion of existing indebtedness under the revolving credit
facility and to fund the acquisition of our European calcium chloride
assets.
In April 2006, we issued, and sold through a
private placement, $90.0 million in aggregate principal amount of Series 2006-A
Senior Notes pursuant to our existing Master Note Purchase Agreement dated
September 2004, as supplemented as of April 18, 2006. The Series 2006-A Senior
Notes were sold in the United States to accredited investors pursuant to an
exemption from the Securities Act of 1933. Net proceeds from the sale of the
Series 2006-A Senior Notes were used to pay down a portion of the existing
indebtedness under the bank revolving credit facility.
In
April 2008, we issued, and sold through a private placement, $35.0 million in
aggregate principal amount of Series 2008-A Senior Notes and $90.0 million in
aggregate principal amount of Series 2008-B Senior Notes (collectively the
Series 2008 Senior Notes) pursuant to a Note Purchase Agreement dated April 30,
2008. The Series 2008 Senior Notes were sold in the United States to accredited
investors pursuant to an exemption from the Securities Act of 1933. A
significant majority of the combined net proceeds from the sale of the Series
2008 Senior Notes was used to pay down a portion of the existing indebtedness
under the bank revolving credit facility.
The Series 2004-A
Senior Notes bear interest at the fixed rate of 5.07% and mature on September
30, 2011. The Series 2004-B Senior Notes bear interest at the fixed rate of
4.79% and mature on September 30, 2011. Interest on the 2004-A Senior Notes and
the 2004-B Senior Notes is due semiannually on March 30
and September 30 of
each year. The Series 2006-A Senior Notes bear interest at the fixed rate of
5.90% and mature on April 30, 2016. Interest on the 2006-A Senior Notes is due
semiannually on April 30 and October 30 of each year. The Series 2008-A Senior
Notes bear interest at the fixed rate of 6.30% and mature on April 30, 2013. The
Series 2008-B Senior Notes bear interest at the fixed rate of 6.56% and mature
on April 30, 2015. We may prepay the Senior Notes, in whole or in part, at any
time at a price equal to 100% of the principal amount outstanding, plus accrued
and unpaid interest and a “make-whole” prepayment premium. The Senior Notes are
unsecured and are guaranteed by substantially all of our wholly-owned U.S.
subsidiaries. The Note Purchase Agreement and the Master Note Purchase
Agreement, as supplemented, contain customary covenants and restrictions and
require us to maintain certain financial ratios, including a minimum level of
net worth and a ratio between our long-term debt balance and a defined measure
of operating cash flow over a twelve month period. The Note Purchase Agreement
and the Master Note Purchase Agreement also contain customary default provisions
as well as a cross-default provision relating to any other of our indebtedness
of $20 million or more. We are in compliance with all covenants and conditions
of the Note Purchase Agreement and the Master Note Purchase Agreement as of
December 31, 2009. Upon the occurrence and during the continuation of an event
of default under the Note Purchase Agreement and the Master Note Purchase
Agreement, as supplemented, the Senior Notes may become immediately due and
payable, either automatically or by declaration of holders of more than 50% in
principal amount of the Senior Notes outstanding at the time.
52
Other Sources -
In addition
to the aforementioned revolving credit facility, we fund our short-term
liquidity requirements from cash generated by operations, from short-term vendor
financing and, to a lesser extent, from leasing with institutional leasing
companies. Should additional capital be required, we believe that we have the
ability to raise such capital through the issuance of additional debt or equity.
However, instability or volatility in the capital markets at the times we need
to access capital may affect the cost of capital and the ability to raise
capital for an indeterminable length of time. As discussed above, our bank
revolving credit facility matures in June 2011 and our Senior Notes mature at
various dates between September 2011 and April 2016. The replacement of these
capital sources at similar or more favorable terms is uncertain. If it is
necessary to utilize equity to fund our capital needs, dilution to our common
stockholders could occur.
In
November 2009, we filed a universal shelf registration statement on Form S-3
that permits us to issue an indeterminate amount of securities including common
stock, preferred stock, senior and subordinated debt securities, warrants and
units. Such securities may be used for working capital needs, capital
expenditures, and expenditures related to general corporate purposes, including
possible future acquisitions. In May 2004, we filed a universal acquisition
shelf registration statement on Form S-4 that permits us to issue up to $400
million of common stock, preferred stock, senior and subordinated debt
securities, and warrants in one or more acquisition transactions that we may
undertake from time to time.
During the fourth quarter of 2008, we
liquidated the swap derivative contracts related to the remainder of Maritech’s
2008 production in exchange for net cash received of approximately $6.5 million.
During the second quarter of 2009, we liquidated certain swap derivative
contracts related to Maritech’s oil production in exchange for net cash received
of approximately $23.1 million, a large majority of which was used to pay a
portion of our outstanding balance of our bank revolving credit facility. As of
December 31, 2009, the market value of our natural gas swap contracts was
approximately $19.9 million. All or a portion of these contracts are marketable
to the corresponding counterparty and could be liquidated in order to generate
additional cash. The liquidation of any of these swap contracts would expose an
additional portion of Maritech’s expected future natural gas production to
market price volatility in future periods.
In January 2004, our Board of Directors
authorized the repurchase of up to $20 million of our common stock. We purchased
$5.7 million of common stock pursuant to this authorization from 2004 through
2005 and have made no purchases pursuant to the authorization since then. We
received $1.2 million, $4.8 million, and $12.1 million during 2009, 2008 and
2007, respectively, from the exercise of stock options by
employees.
Off
Balance Sheet Arrangements
An
“off balance sheet arrangement” is defined as any contractual arrangement to
which an entity that is not consolidated with us is a party, under which we
have, or in the future may have:
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any
obligation under a guarantee contract that requires initial recognition
and measurement under U.S. Generally Accepted Accounting
Principles;
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a retained or
contingent interest in assets transferred to an unconsolidated entity or
similar arrangement that serves as credit, liquidity, or market risk
support to that entity for the transferred
assets;
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any
obligation under certain derivative instruments;
or
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any
obligation under a material variable interest held by us in an
unconsolidated entity that provides financing, liquidity, market risk or
credit risk support to us, or engages in leasing, hedging, or research and
development services with us.
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As
of December 31, 2009 and 2008, we had no “off balance sheet arrangements” that
may have a current or future material effect on our consolidated financial
condition or results of operations.
Commitments and
Contingencies
Litigation
We
are named defendants in several lawsuits and respondents in certain governmental
proceedings arising in the ordinary course of business. While the outcome of
lawsuits or other proceedings against us cannot be predicted with certainty,
management does not reasonably expect these matters to have a material adverse
impact on the financial statements.
53
Insurance Litigation -
Through December 31, 2009, we have expended approximately $55.2 million
on well intervention and debris removal work primarily associated with the three
Maritech offshore platforms and associated wells which were destroyed as a
result of Hurricanes Katrina and Rita in 2005. As a result of submitting claims
associated with well intervention costs expended during 2006 and 2007 and
responding to underwriters’ requests for additional information, approximately
$28.9 million of these well intervention costs were reimbursed; however, our
insurance underwriters maintained that well intervention costs for certain of
the damaged wells did not qualify as covered costs and certain well intervention
costs for qualifying wells were not covered under the policy. In addition, the
underwriters also maintained that there was no additional coverage provided
under an endorsement we obtained in August 2005 for the cost of debris removal
associated with these platforms or for other damage repairs associated with
Hurricanes Katrina and Rita on certain properties in excess of the insured
values provided by the property damage section of the policy. Although we
provided requested information to the underwriters and had numerous discussions
with the underwriters, brokers, and insurance adjusters, we did not receive the
requested reimbursement for these contested costs. As a result, on November 16,
2007, we filed a lawsuit in Montgomery County, Texas, entitled
Maritech Resources, Inc. v. Certain
Underwriters and Insurance Companies at Lloyd’s, London subscribing to Policy
no. GA011150U and Steege Kingston
, in which we sought damages for breach
of contract and various related claims and a declaration of the extent of
coverage of an endorsement to the policy. We also made an alternative claim
against our insurance broker, based on its procurement of the August 2005
endorsement, and a separate claim against underwriters’ insurance adjuster for
its role in handling the insurance claim.
During October
2009, we entered into a settlement agreement with regard to this lawsuit, under
which we received approximately $40.0 million during the fourth quarter of 2009
associated with the August 2005 endorsement and well intervention costs incurred
or to be incurred from Hurricanes Katrina and Rita. Except for approximately
$0.6 million of proceeds expected to be received in March 2010, no significant
additional insurance recoveries of well intervention, debris removal, or excess
property damage costs associated with Hurricanes Katrina and Rita will be
received. Following the collection of these amounts, we have collected
approximately $136.6 million of insurance proceeds associated with damage from
Hurricanes Katrina and Rita. This amount represents substantially all of the
maximum coverage limits pursuant to our policies. We estimate that future well
intervention, abandonment, decommissioning, and debris removal efforts related
to these destroyed platforms will result in approximately $45 million to $50
million of additional costs, and an estimate of these costs has been accrued for
as part of Maritech’s decommissioning liability. As a result of the resolution
of this contingency, the full amount of settlement proceeds is reflected as a
credit to earnings in the fourth quarter of 2009.
Class Action Lawsuit -
Between March 27, 2008 and April 30, 2008, two putative class action
complaints were filed in the United States District Court for the Southern
District of Texas (Houston Division) against us and certain of our officers by
certain stockholders on behalf of themselves and other stockholders who
purchased our common stock between January 3, 2007 and October 16, 2007. The
complaints assert claims under Sections 10(b) and 20(a) of the Securities
Exchange Act of 1934, as amended, and Rule 10b-5
promulgated
thereunder. The complaints allege that the defendants violated the federal
securities laws during the period by, among other things, disseminating false
and misleading statements and/or concealing material facts concerning our
current and prospective business and financial results. The complaints also
allege that, as a result of these actions, our stock price was artificially
inflated during the class period, which enabled our insiders to sell their
personally-held shares for a substantial gain. The complaints seek unspecified
compensatory damages, costs, and expenses. On May 8, 2008, the Court
consolidated these complaints as
In re TETRA Technologies, Inc.
Securities Litigation,
No. 4:08-cv-0965 (S.D. Tex.). On August 27, 2008,
Lead Plaintiff Fulton County Employees’ Retirement System filed its Amended
Consolidated Complaint. On October 28, 2008, we filed a motion to dismiss the
federal class action. On July 9, 2009, the Court issued an opinion dismissing,
without prejudice, most of the claims in this lawsuit but permitting plaintiffs
to proceed on their allegations regarding disclosures pertaining to the
collectability of certain insurance receivables.
Between May 28,
2008 and June 27, 2008, two petitions were filed by alleged stockholders in the
District Courts of Harris County, Texas, 133
rd
and
113
th
Judicial Districts, purportedly on our behalf. The suits name our directors and
certain officers as defendants. The factual allegations in these lawsuits mirror
those in the class action lawsuit, and the claims are for breach of fiduciary
duty, unjust enrichment, abuse of control, gross mismanagement, and waste of
corporate assets. The petitions seek disgorgement, costs, expenses, and
unspecified equitable relief. On September 22, 2008, the 133
rd
District Court consolidated these complaints as
In re TETRA Technologies, Inc.
Derivative Litigation,
Cause No. 2008-23432 (133
rd
Dist. Ct., Harris County, Tex.), and appointed Thomas Prow and Mark Patricola as
Co-Lead Plaintiffs. This lawsuit was
54
stayed by agreement
of the parties pending the Court’s ruling on our motion to dismiss the federal
class action. On September 8, 2009, the plaintiffs in this state court action
filed a consolidated petition which makes factual allegations similar to the
surviving allegations in the federal lawsuit.
At this stage, it is impossible to predict the
outcome of these proceedings or their impact upon us. We currently believe that
the allegations made in the federal complaints and state petitions are without
merit, and we intend to seek dismissal of and vigorously defend against these
actions. While a successful outcome cannot be guaranteed, we do not reasonably
expect these lawsuits to have a material adverse effect.
Environmental
One of our
subsidiaries, TETRA Micronutrients, Inc. (TMI), previously owned and operated a
production facility located in Fairbury, Nebraska. TMI is subject to an
Administrative Order on Consent issued to American Microtrace, Inc. (n/k/a/
TETRA Micronutrients, Inc.) in the proceeding styled
In the Matter of American Microtrace
Corporation
, EPA I.D. No. NED00610550, Respondent, Docket No.
VII-98-H-0016, dated September 25, 1998 (the Consent Order), with regard to the
Fairbury facility. TMI is liable for 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.
In August of 2009, the Environmental Protection
Agency (EPA), pursuant to Sections 308 and 311 of the Clean Water Act (CWA),
served a request for information with regard to a spill of zinc bromide that
occurred on the Mississippi River on March 11, 2009. We timely filed a response
to that request for information in August 2009. In January 2010, the EPA issued
a Notice of Violation and Opportunity to Show Cause related to the spill. We
expect to meet with the EPA soon to discuss potential violations and penalties.
It has been agreed that no injunctive relief will be required. Though penalties
have not yet been discussed, it is possible that they will exceed
$100,000.
Product
Purchase Obligations
In
the normal course of our Fluids Division operations, we enter into supply
agreements with certain manufacturers of various raw materials and finished
products. Some of these agreements have terms and conditions that specify a
minimum or maximum level of purchases over the term of the agreement. Other
agreements require us to purchase the entire output of the raw material or
finished product produced by the manufacturer. Our purchase obligations under
these agreements apply only with regard to raw materials and finished products
that meet specifications set forth in the agreements. We recognize a liability
for the purchase of such products at the time we receive them. During 2006, we
significantly increased our purchase obligations as a result of the execution of
a long-term supply agreement with Chemtura Corporation. As of December 31, 2009,
the aggregate amount of the fixed and determinable portion of the purchase
obligation pursuant to our Fluids Division’s supply agreements was approximately
$278.6 million, extending through 2029.
Other
Contingencies
Related to its
acquired interests in oil and gas properties, our Maritech subsidiary estimates
the third-party fair values (including an estimated profit) to plug and abandon
wells, decommission the pipelines and platforms, and clear the sites, and uses
these estimates to record Maritech’s decommissioning liabilities, net of amounts
allocable to joint interest owners and any amounts contractually agreed to be
paid in the future by the previous owners of the properties. In some cases,
previous owners of acquired oil and gas properties are contractually obligated
to pay Maritech a fixed amount for the future well abandonment and
decommissioning work on these properties as such work is performed. As of
December 31, 2009, Maritech’s decommissioning liabilities are net of
approximately $43.6 million for such future reimbursements from these previous
owners.
55
Contractual
Obligations
The table below
summarizes our contractual cash obligations as of December 31,
2009:
|
Payments
Due
|
||||||||||||||||||||||||||||
|
Total
|
2010
|
2011
|
2012
|
2013
|
2014
|
Thereafter
|
||||||||||||||||||||||
|
(In
Thousands)
|
||||||||||||||||||||||||||||
|
Long-term
debt
|
$ | 310,132 | $ | - | $ | 95,132 | $ | - | $ | 35,000 | $ | - | $ | 180,000 | ||||||||||||||
|
Interest on
debt
|
80,641 | 18,130 | 16,942 | 13,419 | 11,939 | 11,214 | 8,997 | |||||||||||||||||||||
|
Purchase
obligations
|
278,605 | 12,595 | 13,935 | 15,275 | 15,275 | 15,275 | 206,250 | |||||||||||||||||||||
|
Decommissioning
and
|
||||||||||||||||||||||||||||
|
other
asset retirement
|
||||||||||||||||||||||||||||
|
obligations
(1)
|
233,952 | 76,179 | (3) | 39,167 | 17,809 | 21,193 | 15,132 | 64,472 | ||||||||||||||||||||
|
Operating
and
|
||||||||||||||||||||||||||||
|
capital
leases
|
11,370 | 4,738 | 2,453 | 1,853 | 1,123 | 808 | 395 | |||||||||||||||||||||
|
Total
contractual
|
||||||||||||||||||||||||||||
|
cash
obligations
(2)
|
$ | 914,700 | $ | 111,642 | $ | 167,629 | $ | 48,356 | $ | 84,530 | $ | 42,429 | $ | 460,114 | ||||||||||||||
|
(1)
|
Decommissioning liabilities related to oil and gas properties generally must be satisfied within twelve months after a property’s lease expires. Lease expiration generally occurs six months after the last producing well on the lease ceases production. We have estimated the timing of these payments based upon anticipated lease expiration dates, which are subject to many changing variables, including the estimated life of the producing oil and gas properties, which is affected by changing oil and gas commodity prices. The amounts shown represent the undiscounted obligation as of December 31, 2009. |
|
(2)
|
Amounts exclude other long-term liabilities reflected in our Consolidated Balance Sheet that do not have known payment streams. These excluded amounts include approximately $4.3 million of liabilities under FASB Codification Topic 740, “Accounting for Uncertainty in Income Taxes,” as we are unable to reasonably estimate the ultimate amount or timing of settlements. See “Note F – Income Taxes,” in the Notes to Consolidated Financial Statements for further discussion. |
| (3) | Approximately $59.0 million of the amounts expected to be paid in 2010 represent well intervention, abandonment, decommissioning, and debris removal related to offshore platforms destroyed in the 2005 and 2008 hurricanes, net of anticipated insurance recoveries. |
Recently
Issued Accounting Pronouncements
In
June 2009, the Financial Accounting Standards Board (FASB) published Statement
of Financial Accounting Standard (SFAS) No. 168, “The
FASB Accounting Standards
Codification
and the Hierarchy of Generally Accepted Accounting
Principles – a replacement of FASB Statement No. 162,” which establishes the
FASB Accounting Standards
Codification
(FASB Codification) as the source of authoritative U.S.
generally accepted accounting principles (GAAP) recognized by the FASB to be
applied by nongovernmental entities. Beginning on the effective date of the
standard (now incorporated into FASB Codification Subtopic 105-10), the FASB
Codification superseded all then-existing non-SEC accounting and reporting
standards. All other non-grandfathered non-SEC accounting literature not
included in the FASB Codification has become non-authoritative. The standard is
effective for financial statements issued for interim and annual periods ending
after September 15, 2009. In the FASB’s view, the issuance of the standard and
the FASB Codification will not change GAAP for public companies, and,
accordingly, the adoption of the standard did not have a significant impact on
our financial statements.
In
March 2008, the FASB published SFAS No. 161, “Disclosures about Derivative
Instruments and Hedging Activities, an amendment of FASB Statement No. 133,”
(FASB Codification Topic 815, “Derivatives and Hedging”), which requires
entities to provide greater transparency about (1) how and why an entity uses
derivative instruments, (2) how derivative instruments and related hedged items
are accounted for under FASB Codification Topic 815 (SFAS No. 133 and its
related interpretations); and (3) how derivative
instruments and
related hedged items affect an entity’s financial position, results of
operations, and cash flows. This standard is effective for financial statements
issued for fiscal years and interim periods within those fiscal years beginning
after November 15, 2008. Accordingly, we adopted the new disclosure requirements
as of January 1, 2009.
In
December 2007, the FASB published SFAS No. 141R, “Business Combinations,”
(incorporated into FASB Codification Topic 805, “Business Combinations”), which
established principles and requirements for how an acquirer of a business (1)
recognizes and measures in its financial statements the identifiable assets
acquired, the liabilities assumed, and any noncontrolling interest in the
acquiree; (2) recognizes and measures the goodwill acquired in the business
combination or a gain from a bargain purchase; and (3) determines what
information to disclose to enable users of the financial statements to evaluate
the nature and
56
financial effects
of the business combination. The standard changes many aspects of the accounting
for business combinations and applies prospectively to business combinations for
which the acquisition date is on or after the beginning of the first annual
reporting period beginning on or after December 15, 2008. We adopted this
standard as of January 1, 2009 with no significant impact, as there have been no
acquisitions during 2009. However, the standard is expected to significantly
impact how we account for and disclose future acquisition
transactions.
In
May 2009, the FASB published SFAS No. 165, “Subsequent Events,” (FASB
Codification Topic 855, “Subsequent Events”), which establishes general
standards of accounting for and disclosure of events that occur after the
balance sheet date but before financial statements are issued or are available
to be issued. In particular, it sets forth (1) the period after the balance
sheet date during which management of a reporting entity should evaluate events
or transactions that may occur for potential recognition or disclosure; (2) the
circumstances under which an entity should recognize events or transactions
occurring after the balance sheet date; and (3) the disclosures that an entity
should make about events or transactions that occurred after the balance sheet
date. This standard is effective for financial statements for periods ending
after June 15, 2009. We adopted this standard as of July 1, 2009, however the
standard did not have a significant impact on our financial
statements.
In
December 2008, the SEC released its “Modernization of Oil and Gas Reporting”
rules, which revise the disclosure of oil and gas reserve information. The new
disclosure requirements include provisions that permit the use of new
technologies to determine proved reserves in certain circumstances. The new
requirements also will allow companies to disclose their probable and possible
reserves and require companies to (1) report on the independence and
qualifications of a reserves preparer or auditor; (2) file reports when a third
party is relied upon to prepare reserve estimates or conduct a reserves audit;
and (3) report oil and gas reserves using an average price based upon the prior
twelve month period, rather than year-end prices. These new reporting
requirements are effective for annual reports on Form 10-K for fiscal years
ending on or after December 31, 2009. We adopted these new SEC oil and gas
reserve rules as of December 31, 2009, however they did not have a significant
impact on our financial statements.
Interest Rate
Risk
Any balances
outstanding under the floating rate portion of our bank credit facility are
subject to market risk exposure related to changes in applicable interest rates.
We borrow funds pursuant to our bank credit facility as necessary to fund our
capital expenditure requirements and certain acquisitions. These instruments
carry interest at an agreed-upon percentage rate spread above LIBOR. We had no
balance outstanding under our bank credit facility as of December 31, 2009.
Accordingly, as of that date, there are no long-term debt obligations which bear
a variable rate of interest.
The following table
sets forth, as of December 31, 2009, our cash flows for the outstanding
principal balance of our long-term debt obligations which bear a variable rate
of interest and weighted average effective interest rates by their expected
maturity dates. 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.
|
Expected
Maturity Date
|
Fair
|
|||||||||||||||||||||||||||||||
|
2009
|
2010
|
2011
|
2012
|
2013
|
Thereafter
|
Total
|
Market
Value
|
|||||||||||||||||||||||||
|
(In
Thousands, Except Percentages)
|
||||||||||||||||||||||||||||||||
|
As
of December 31, 2009
|
||||||||||||||||||||||||||||||||
|
Long-term
debt:
|
||||||||||||||||||||||||||||||||
|
U.S. dollar
variable rate
|
$ | - | $ | - | $ | - | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||||||||
|
Euro variable
rate (in $US)
|
- | - | - | - | - | - | - | - | ||||||||||||||||||||||||
|
Weighted
average
|
||||||||||||||||||||||||||||||||
|
interest
rate
|
- | - | - | - | - | - | - | - | ||||||||||||||||||||||||
|
Variable to
fixed swaps
|
- | - | - | - | - | - | - | - | ||||||||||||||||||||||||
|
Fixed pay
rate
|
- | - | - | - | - | - | - | - | ||||||||||||||||||||||||
|
Variable
receive rate
|
- | - | - | - | - | - | - | - | ||||||||||||||||||||||||
57
Exchange Rate
Risk
We are exposed to fluctuations between the U.S.
dollar and the euro with regard to our euro-denominated operating activities and
related long-term euro denominated debt. In September 2004, we borrowed euros to
fund the acquisition of our European calcium chloride assets. We entered into
long-term euro-denominated borrowings, as we believe such borrowings provide a
natural currency hedge for our euro-based operating cash flow. In our European
operations, we also have exposure related to revenues, expenses, operating
receivables, and payables denominated in euros as well as other currencies;
however, such transactions are not pursuant to long-term contract terms, and the
amount of such foreign currency exposure is not determinable or considered
material. We also have operations in other foreign countries in which we have
exposure to the fluctuation between the local currencies in those markets and
the U.S. dollar. We currently have no hedges in place with regard to these
currencies.
The following table sets forth as of December
31, 2009 our cash flows for the outstanding principal balances of our long-term
debt obligations which are denominated in euros. This information is presented
in U.S. dollar equivalents. The table presents principal cash flows and related
weighted average interest rates by their expected maturity dates. As described
above, we utilize the long-term borrowings detailed in the following table as a
hedge to our investment in our acquired foreign operations, and, currently, we
are not a party to a foreign currency swap contract or other derivative
instrument designed to further hedge our currency exchange rate risk exposure.
Our exchange rate risk exposure related to these borrowings will generally be
offset by the offsetting fluctuations in the value of the related foreign
investment.
|
Expected
Maturity Date
|
Fair
|
|||||||||||||||||||||||||||||||
|
2010
|
2011
|
2012
|
2013
|
2014
|
Thereafter
|
Total
|
Market
Value
|
|||||||||||||||||||||||||
|
(In
Thousands, Except Percentages)
|
||||||||||||||||||||||||||||||||
|
As
of December 31, 2009
|
||||||||||||||||||||||||||||||||
|
Long-term
debt:
|
||||||||||||||||||||||||||||||||
|
Euro variable
rate (in $US)
|
$ | - | $ | - | $ | - | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||||||||
|
Euro fixed
rate (in $US)
|
- | 40,132 | - | - | - | - | - | 40,357 | ||||||||||||||||||||||||
|
Weighted
average
|
||||||||||||||||||||||||||||||||
|
interest
rate
|
- | 4.790 | % | - | - | - | - | 4.790 | % | - | ||||||||||||||||||||||
|
Variable to
fixed swaps
|
- | - | - | - | - | - | - | - | ||||||||||||||||||||||||
|
Fixed pay
rate
|
- | - | - | - | - | - | - | - | ||||||||||||||||||||||||
|
Variable
receive rate
|
- | - | - | - | - | - | - | - | ||||||||||||||||||||||||
Commodity Price
Risk
We
have market risk exposure in the pricing applicable to our oil and gas
production. Realized pricing is primarily driven by the prevailing worldwide
price for crude oil and spot prices in the U.S. natural gas market.
Historically, prices received for oil and gas production have been volatile and
unpredictable, and such price volatility is expected to continue. Our risk
management activities involve the use of derivative financial instruments, such
as swap agreements, to hedge the impact of market price risk exposures for a
portion of our oil and gas production. We are exposed to the volatility of oil
and gas prices for the portion of our oil and gas production that is not hedged.
Net of the impact of the crude oil and natural gas hedges as of December
31,
2009, described below, each $1 per barrel decrease in future crude oil prices
would result in a decrease in after tax earnings of $0.4 million and each
decrease in future gas prices of $0.10 per Mcf would result in a decrease in
after tax earnings of $0.2 million.
FASB Codification
Topic 815, “Derivatives and Hedging,” requires companies to record derivatives
on the balance sheet as assets and liabilities, measured at fair value. Gains or
losses resulting from changes in the values of those derivatives are accounted
for depending on the use of the derivative and whether it qualifies for hedge
accounting. As of December 31, 2009 and 2008, we had the following cash flow
hedging swap contracts outstanding relating to a portion of our Maritech
subsidiary’s oil and gas production:
58
|
Commodity
Contracts
|
Aggregate
Daily
Volume
|
Weighted
Average Contract Price
|
Contract
Year
|
|||
|
December 31, 2009
|
||||||
|
Oil
swaps
|
2,000
barrels/day
|
$78.70/barrel
|
2010
|
|||
|
Natural gas
swaps
|
20,000
MMBtu/day
|
$8.147/MMBtu
|
2010
|
|||
|
December 31, 2008
|
||||||
|
Oil
swaps
|
2,500
barrels/day
|
$68.864/barrel
|
2009
|
|||
|
Oil
swaps
|
2,000
barrels/day
|
$104.125/barrel
|
2010
|
|||
|
Natural gas
swaps
|
25,000
MMBtu/day
|
$8.967/MMBtu
|
2009
|
|||
|
Natural gas
swaps
|
10,000
MMBtu/day
|
$10.265/MMBtu
|
2010
|
In
January 2010, we entered into an additional cash flow hedging oil swap contract,
covering 1,000 barrels/day from February to December 2010, with a contract price
of $84.90/barrel. During the second quarter of 2009, we liquidated cash flow
hedging oil swap contracts in exchange for cash of approximately $23.1
million.
Each oil and gas
swap contract uses the NYMEX WTI (West Texas Intermediate) oil price and the
NYMEX Henry Hub natural gas price as the referenced price. Based upon an average
NYMEX strip price over the remaining contract term of $82.31/barrel, the market
value of our oil swaps liability at December 31, 2009 was $2.6 million. A $1
increase in the future price of oil would result in the market value of the
combined oil derivative liability increasing by $0.7 million. Based on an
average NYMEX strip price over the remaining contract term of $5.79/MMBtu, the
market value of our natural gas swaps asset at December 31, 2009 was $19.9
million. A $0.10 increase in the future price of natural gas would result in the
market value of the combined natural gas derivative asset decreasing by $0.7
million. The market value associated with the 2010 natural gas swap contracts is
reflected as a current asset, and the market value associated with the 2010 oil
swap contracts is reflected as a current liability in the accompanying
consolidated balance sheet.
The market value of
our oil swaps asset at December 31, 2008 was $41.5 million. A $1 increase in the
future price of oil would have resulted in the market value of the combined oil
derivative asset decreasing by $1.6 million. The market value of our natural gas
swaps asset at December 31, 2008 was $35.7 million. A $0.10 increase in the
future price of natural gas would result in the market value of the combined
natural gas derivative asset decreasing by $1.3 million.
Our financial
statements and supplementary data for us and our subsidiaries required to be
included in this Item 8 are set forth in Item 15 of this
Report.
None.
Conclusion Regarding the
Effectiveness of Disclosure Controls and Procedures
Under the
supervision and with the participation of our management, including our Chief
Executive Officer and Chief Financial Officer, we conducted an evaluation of our
disclosure controls and procedures, as such term is defined under Rule 13a-15(e)
promulgated under the Securities Exchange Act of 1934, as amended (the Exchange
Act). Based on this evaluation, the Chief Executive Officer and Chief Financial
Officer concluded that our disclosure controls and procedures were effective as
of December 31, 2009, the end of the period covered by this annual
report.
59
Management’s Report on
Internal Control over Financial Reporting
Our management is
responsible for establishing and maintaining adequate internal control over
financial reporting, as such term is defined in Exchange Act Rule 13a-15(f).
Under the supervision and with the participation of management, including our
Chief Executive Officer and Chief Financial Officer, an evaluation of the
effectiveness of our internal control over financial reporting was conducted
based on the framework in Internal Control – Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based
on that evaluation under the framework in Internal Control – Integrated
Framework issued by the COSO, our management concluded that our internal control
over financial reporting was effective as of December 31, 2009.
An
assessment of the effectiveness of our internal control over financial reporting
as of December 31, 2009 has been performed by Ernst & Young LLP, an
independent registered public accounting firm, as stated in their report which
is included herein.
Changes in Internal Control
over Financial Reporting
There were no
changes in our internal control over financial reporting during the fiscal
quarter ending December 31, 2009 that have materially affected, or are
reasonably likely to materially affect, our internal control over financial
reporting.
None.
60
The information
required by this Item is hereby incorporated by reference from the information
appearing under the captions “Proposal No. 1: Election of Directors,” “Executive
Officers,” “Corporate Governance,” “Board Meetings and Committees,” and “Section
16(a) Beneficial Ownership Reporting Compliance” in our definitive proxy
statement (the Proxy Statement) for the annual meeting of stockholders to be
held May 5, 2010, which involves the election of directors and is to be filed
with the Securities and Exchange Commission (SEC) pursuant to the Securities
Exchange Act of 1934 as amended (the Exchange Act) within 120 days of the end of
our fiscal year on December 31, 2009.
The information
required by this Item is hereby incorporated by reference from the information
appearing under the captions “Management and Compensation Committee Report,”
“Management and Compensation Committee Interlocks and Insider Participation,”
“Compensation Discussion and Analysis,” “Compensation of Executive Officers,”
and “Director Compensation” in our Proxy Statement. Notwithstanding the
foregoing, in accordance with the instructions to Item 407 of Regulation S-K,
the information contained in our Proxy Statement under the subheading
“Management and Compensation Committee Report” 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 Exchange Act, as a
result of this furnishing, except to the extent we specifically incorporate it
by reference.
The information
required by this Item is hereby incorporated by reference from the information
appearing under the captions “Beneficial Stock Ownership of Certain Stockholders
and Management” and “Equity Compensation Plan Information” in our Proxy
Statement.
The information
required by this Item is hereby incorporated by reference from the information
appearing under the captions “Certain Transactions” and “Director Independence”
in our Proxy Statement.
The information required by this Item is hereby
incorporated by reference from the information appearing under the caption “Fees
Paid to Principal Accounting Firm” in our Proxy Statement.
61
(a) List of
documents filed as part of this Report
|
1.
|
Financial
Statements of the Company
|
|
|
Page
|
||
|
Reports of
Independent Registered Public Accounting Firm
|
F-1
|
|
|
Consolidated
Balance Sheets at December 31, 2009 and 2008
|
F-3
|
|
|
Consolidated
Statements of Operations for the years ended
December
31, 2009, 2008, and 2007
|
F-5
|
|
|
Consolidated
Statements of Stockholders’ Equity for the years ended
December
31, 2009, 2008, and 2007
|
F-6
|
|
|
Consolidated
Statements of Cash Flows for the years ended
December
31, 2009, 2008, and 2007
|
F-7
|
|
|
Notes to
Consolidated Financial Statements
|
F-8
|
|
|
2.
|
Financial
statement schedules have been omitted as they are not required, are not
applicable, or the required information is included in the financial
statements or notes thereto.
|
|
|
3.
|
List of
Exhibits
|
|
|
3.1
|
Restated
Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by
reference to Exhibit 3.1 to the Company’s Registration Statement on Form
S-4 filed on December 27, 1995 (SEC File No.
33-80881)).
|
|
3.2
|
Certificate of
Amendment of Restated Certificate of Incorporation of TETRA Technologies,
Inc. (incorporated by reference to Exhibit 3.1 to the Company’s
Registration Statement on Form S-4 filed on December 27, 1995 (SEC File
No. 33-80881)).
|
|
|
3.3
|
Certificate of
Amendment of Restated Certificate of Incorporation of TETRA Technologies,
Inc. (incorporated by reference to Exhibit 3.1(ii) to the Company’s Annual
Report on Form 10-K for the year ended December 31, 2003 filed on March
15, 2004 (SEC File No. 001-13455)).
|
|
|
3.4
|
Certificate of
Amendment of Restated Certificate of Incorporation of TETRA Technologies,
Inc. (incorporated by reference to Exhibit 4.4 to the Company’s
Registration Statement on Form S-4 filed on May 25, 2004 (SEC File No.
333-115859)).
|
|
|
3.5
|
Certificate of
Amendment of Restated Certificate of Incorporation of TETRA Technologies,
Inc. (incorporated by reference to Exhibit 4.5 to the Company’s
Registration Statement on Form S-8 filed on May 4, 2006 (SEC File No.
333-133790)).
|
|
|
3.6
|
Certificate of
Designation of Series One Junior Participating Preferred Stock of the
Company dated October 27, 1998 (incorporated by reference to Exhibit 2 to
the Company’s Registration Statement on Form 8-A filed on October 28, 1998
(SEC File No. 001-13455)).
|
|
|
3.7
|
Amended and
Restated Bylaws of TETRA Technologies, Inc. (incorporated by reference to
Exhibit 4.6 to the Company’s Registration Statement on Form S-8 filed on
May 4, 2006 (SEC File No. 333-133790)).
|
|
|
4.1
|
Rights
Agreement dated October 26, 1998 between the Company and Computershare
Investor Services LLC (as successor in interest to Harris Trust &
Savings Bank), as Rights Agent (incorporated by reference to Exhibit 1 to
the Company’s Registration Statement on Form 8-A filed on October 28, 1998
(SEC File No. 001-13455)).
|
|
|
4.2
|
Master Note
Purchase Agreement, dated September 27, 2004 by and among TETRA
Technologies, Inc. and Jackson National Life Insurance Company,
Massachusetts Mutual Life Insurance Company, C.M. Life Insurance Company,
Allstate Life Insurance Company, Teachers Insurance and Annuity
Association of America, Pacific Life Insurance Company, the Prudential
Assurance Company Limited (PAC), and Panther CDO II, B.V. (incorporated by
reference to Exhibit 4.1 to the Company’s Form 8-K filed on September 30,
2004 (SEC File No. 001-13455)).
|
|
|
4.3
|
Form of 5.07%
Senior Notes, Series 2004-A, due September 30, 2011 (incorporated by
reference to Exhibit 4.2 to the Company’s Form 8-K filed on September 30,
2004 (SEC File No.
001-13455)).
|
62
|
4.4
|
Form of 4.79%
Senior Notes, Series 2004-B, due September 30, 2011 (incorporated by
reference to Exhibit 4.3 to the Company’s Form 8-K filed on September 30,
2004 (SEC File No. 001-13455)).
|
|
|
4.5
|
Form of
Subsidiary Guaranty dated September 27, 2004, executed by TETRA Applied
Holding Company, TETRA International Incorporated, TETRA Micronutrients,
Inc., TETRA Process Services, Inc., TETRA Thermal, Inc., Maritech
Resources, Inc., Seajay Industries, Inc., TETRA Investment Holding Co.,
Inc., TETRA Financial Services, Inc., Compressco, Inc., Providence Natural
Gas, Inc., TETRA Applied LP, LLC, TETRA Applied GP, LLC, TETRA Production
Testing GP, LLC, TPS Holding Company, LLC, T Production Testing, LLC,
TETRA Real Estate, LLC, TETRA Real Estate, LP, Compressco Testing, L.L.C.,
Compressco Field Services, Inc., TETRA Production Testing Services, L.P.,
and TETRA Applied Technologies, L. P., for the benefit of the holders of
the Notes (incorporated by reference to Exhibit 4.4 to the Company’s Form
8-K filed on September 30, 2004 (SEC File No.
001-13455)).
|
|
|
4.6
|
First
Supplement to Master Note Purchase Agreement, dated April 18, 2006,
by and among TETRA Technologies, Inc. and Jackson National Life Insurance
Company, Allianz Life Insurance Company of North America, United of Omaha
Life Insurance Company, Mutual of Omaha Insurance Company, CUNA Mutual
Life Insurance Company, CUNA Mutual Insurance Society, CUMIS Insurance
Society, Inc., Members Life Insurance Company, and Modern Woodmen of
America, attaching the form of the 5.90% Senior Notes, Series 2006-A, due
April 30, 2016 as an exhibit thereto (incorporated by reference to Exhibit
4.1 to the Company’s Form 8-K filed on April 20, 2006 (SEC File No.
001-13455)).
|
|
|
4.7
|
Note Purchase
Agreement, dated April 30, 2008, by and among TETRA Technologies, Inc. and
The Prudential Insurance Company of America, Physicians Mutual Insurance
Company, The Lincoln National Life Insurance Company, The Guardian Life
Insurance Company of America, The Guardian Insurance & Annuity
Company, Inc., Massachusetts Mutual Life Insurance Company, Hakone Fund II
LLC, C.M. Life Insurance Company, Pacific Life Insurance Company, United
of Omaha Life Insurance Company, Companion Life Insurance Company, United
World Life Insurance Company, Country Life Insurance Company, The Ohio
National Life Insurance Company and Ohio National Life Assurance
Corporation (incorporated by reference to Exhibit 4.1 to the Company’s
Form 8-K filed on May 5, 2008 (SEC File No.
001-13455)).
|
|
|
4.8
|
First
Amendment to Rights Agreement dated as of November 6, 2008, by and between
TETRA Technologies, Inc. and Computershare Trust Company, N.A. (as
successor rights agent to Harris Trust and Savings Bank), as Rights Agent
(incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed
on November 6, 2008 (SEC File No. 001-13455)).
|
|
|
4.9
|
Form of 6.30%
Senior Notes, Series 2008-A, due April 30, 2013 (incorporated by reference
to Exhibit 4.2 to the Company’s Form 8-K filed on May 5, 2008 (SEC File
No. 001-13455)).
|
|
|
4.10
|
Form of 6.56%
Senior Notes, Series 2008-B, due April 30, 2015 (incorporated by reference
to Exhibit 4.3 to the Company’s Form 8-K filed on May 5, 2008 (SEC File
No. 001-13455)).
|
|
|
4.11
|
Form of
Subsidiary Guarantee dated as of April 30, 2008, executed by Beacon
Resources, LLC, Compressco Field Services, Inc., EPIC Diving and Marine
Services, LLC, Maritech Resources, Inc., TETRA Applied Technologies, LLC,
TETRA International Incorporated, TETRA Process Services, L.C., TETRA
Production Testing Services, LLC, and Maritech Timbalier Bay, LP, for the
benefit of the holders of the Notes (incorporated by reference to Exhibit
4.4 to the Company’s Form 8-K filed on May 5, 2008 (SEC File No.
0001-13455)).
|
|
|
10.1***
|
1990 Stock
Option Plan, as amended through January 5, 2001 (incorporated by reference
to Exhibit 10.8 to the Company’s Form 10-K for the year ended December 31,
2000 filed on March 30, 2001 (SEC File No. 001-13455)).
|
|
|
10.2***
|
Director Stock
Option Plan (incorporated by reference to Exhibit 10.9 to the Company’s
Form 10-K for the year ended December 31, 2000 filed on March 30, 2001
(SEC File No. 001-13455)).
|
|
|
10.3***
|
1998 Director
Stock Option Plan (incorporated by reference to Exhibit 10.10 to the
Company’s Form 10-K for the year ended December 31, 2000 filed on March
23, 2001 (SEC File No. 001-13455)).
|
|
|
10.4***
|
1996 Stock
Option Plan for Nonexecutive Employees and Consultants (incorporated by
reference to Exhibit 99.1 to the Company’s Registration Statement on Form
S-8 filed on November 19, 1997 (SEC File No.
333-61988)).
|
|
|
10.5***
|
Letter of
Agreement with Gary C. Hanna, dated March, 2002 (incorporated by reference
to Exhibit 10.8 to the Company’s Form 10-K for the year ended December 31,
2001 filed on March 29, 2002 (SEC File No. 001-13455)).
|
|
|
10.6***
|
1998 Director
Stock Option Plan (incorporated by reference to Exhibit 10.8 to the
Company’s Form 10-K for the year ended December 31, 2002 filed on March
28, 2003 (SEC File No. 001-13455)).
|
63
|
10.7
|
Credit Agreement dated as of
September 7, 2004, among TETRA Technologies, Inc. and certain of its
subsidiaries, as borrowers, Bank of America, National Association, as
Administrative Agent, Bank One, NA and Wells Fargo Bank, N.A., as
syndication agents, and Comerica Bank, as documentation agent, attaching
the guaranty dated as of September 7, 2004, by the borrowers, as
guarantors, to the Administrative Agent for the benefit of the lenders
under the Credit Agreement (incorporated by reference to Exhibit 10.1 to
the Company’s Form 8-K filed on September 8, 2004 (SEC File No.
001-13455)).
|
|
|
10.8***
|
Agreement between TETRA
Technologies, Inc. and Geoffrey M. Hertel, dated February 26, 1993
(incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed
on January 7, 2005 (SEC File No. 001-13455)).
|
|
|
10.9***
|
Form of Incentive Stock Option
Agreement, dated as of December 28, 2004 (incorporated by reference to
Exhibit 10.1 to the Company’s Form 8-K filed on January 7, 2005 SEC File
No. 001-13455)).
|
|
|
10.10***
|
TETRA Technologies, Inc. 2006
Equity Incentive Compensation Plan (incorporated by reference to Exhibit
4.12 to the Company’s Registration Statement on Form S-8 filed on May 4,
2006 (SEC File No. 333-133790)).
|
|
|
10.11***
|
Forms of Employee Incentive
Stock Option Agreement, Employee Nonqualified Stock Option Agreement, and
Employee Restricted Stock Agreement under the TETRA Technologies, Inc.
2006 Equity Incentive Compensation Plan (incorporated by reference to
Exhibits 10.1, 10.2, and 10.3 to the Company’s Form 8-K filed on May 8,
2006 (SEC File No. 001-13455)).
|
|
|
10.12+***
|
Summary Description
of the Compensation of Non-Employee Directors of TETRA Technologies,
Inc.
|
|
|
10.13+***
|
Summary Description
of Named Executive Officer Compensation.
|
|
|
10.14
|
Purchase and Sale Agreement by
and between Pioneer Natural Resources USA, Inc. as Seller and Maritech
Resources, Inc. as Purchaser, dated July 7, 2005 (incorporated by
reference to Exhibit 10.1 to the Company’s Form 10-Q filed on November 9,
2005 (SEC File No. 001-13455), certain portions of this exhibit have been
omitted pursuant to a confidential treatment request filed with the
Securities and Exchange Commission).
|
|
|
10.15***
|
Nonqualified Stock Option
Agreement between TETRA Technologies, Inc. and Stuart M. Brightman, dated
April 20, 2005 (incorporated by reference to Exhibit 10.1 to the Company’s
Form 8-K filed on April 22, 2005 (SEC File No.
001-13455)).
|
|
|
10.16***
|
First Amendment to
the TETRA Technologies, Inc. 1998 Director Stock Option Plan (As Amended
Through June 27, 2003), dated December 16, 2005 (incorporated by reference
to Exhibit 10.1 to the Company’s Form 8-K filed on December 22, 2005 (SEC
File No. 001-13455)).
|
|
|
10.17***
|
Form of Stock Option Agreement
under the TETRA Technologies, Inc. 1998 Director Stock Option Plan (As
Amended Through June 27, 2003), as further amended by the First Amendment
to the TETRA Technologies, Inc. 1998 Director Stock Option Plan (As
Amended Through June 27, 2003) (incorporated by reference to Exhibit 10.2
to the Company’s Form 8-K filed on December 22, 2005 (SEC File No.
001-13455)).
|
|
|
10.18
|
Agreement and Third Amendment
to Credit Agreement, dated as of January 20, 2006, among TETRA
Technologies, Inc. and certain of its subsidiaries, as borrowers, JP
Morgan Chase Bank, National Association (successor to Bank One, NA) and
Wells Fargo Bank, N.A., as syndication agents, Comerica Bank, as
documentation agent, Bank of America, National Association, as
administrative agent, and the lenders party thereto (incorporated by
reference to Exhibit 10.1 to the Company’s Form 8-K filed on January 23,
2006 (SEC File No. 001-13455)).
|
|
|
10.19
|
Credit Agreement, as amended
and restated, dated as of June 27, 2006, among TETRA Technologies, Inc.
and certain of its subsidiaries, as borrowers, JPMorgan Chase Bank, N.A.,
as administrative agent, Bank of America, National Association and Wells
Fargo Bank, N.A., as syndication agents, and Comerica Bank, as
documentation agent, and the lenders party thereto (incorporated by
reference to Exhibit 10.1 to the Company’s Form 8-K filed on June 30, 2006
(SEC File No. 001-13455)).
|
|
|
10.20
|
Agreement and First Amendment
to Credit Agreement, dated as of December 15, 2006, among TETRA
Technologies, Inc. and certain of its subsidiaries, as borrowers, JPMorgan
Chase Bank, N.A., as administrative agent, Bank of America, National
Association and Wells Fargo Bank, N.A., as syndication agents, and
Comerica Bank, as documentation agent, and the lenders party thereto
(incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed
on January 10, 2007 (SEC File No. 001-13455)).
|
|
|
10.21***
|
TETRA Technologies, Inc.
Nonqualified Deferred Compensation Plan (incorporated by reference to
Exhibit 10.9 to the Company’s Form 10-Q filed on August 13, 2002 (SEC File
No. 001-13455)).
|
|
|
10.22***
|
TETRA Technologies, Inc.
Nonqualified Deferred Compensation Plan and The Executive Excess Plan
Adoption Agreement effective on June 30, 2005 (incorporated by reference
to Exhibit 10.2 to the Company’s Form 10-Q/A filed on March 16, 2006 (SEC
File No. 001-13455)).
|
64
|
10.23***
|
TETRA
Technologies, Inc. 2007 Equity Incentive Compensation Plan (incorporated
by reference to Exhibit 4.12 to the Company’s Registration Statement on
Form S-8 filed on May 4, 2007 (SEC File No.
333-142637)).
|
|
|
10.24***
|
Forms of
Employee Incentive Stock Option Agreement, Employee Nonqualified Stock
Option Agreement, and Employee Restricted Stock Agreement under the TETRA
Technologies, Inc. 2007 Equity Incentive Compensation Plan (incorporated
by reference to Exhibits 4.13, 4.14, and 4.15 to the Company’s
Registration Statement on Form S-8 filed on May 4, 2007 (SEC File No.
333-142637)).
|
|
|
10.25***
|
TETRA
Technologies, Inc. 401(k) Retirement Plan, as amended and restated
(incorporated by reference to Exhibit 99.1 to the Company’s Registration
Statement on Form S-8 filed on February 22, 2008 (SEC File No.
333-149348)).
|
|
|
10.26***
|
Employee
Restricted Stock Agreement between TETRA Technologies, Inc. and Philip N.
Longorio, dated February 22, 2008 (incorporated by reference to Exhibit
4.12 to the Company’s Registration Statement on Form S-8 filed on February
22, 2008 (SEC File No. 333-149347)).
|
|
|
10.27***
|
TETRA
Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation
Plan (incorporated by reference to Exhibit 4.12 to the Company’s
Registration Statement on Form S-8 filed on May 9, 2008 (SEC File No.
333-150783)).
|
|
|
10.28***
|
Form of
Employee Incentive Stock Option Agreement under the TETRA Technologies,
Inc. Amended and Restated 2007 Equity Incentive Compensation Plan
(incorporated by reference to Exhibit 4.13 to the Company’s Registration
Statement on Form S-8 filed on May 9, 2008 (SEC File No.
333-150783)).
|
|
|
10.29***
|
Form of
Employee Nonqualified Stock Option Agreement under the TETRA Technologies,
Inc. Amended and Restated 2007 Equity Incentive Compensation Plan
(incorporated by reference to Exhibit 4.14 to the Company’s Registration
Statement on Form S-8 filed on May 9, 2008 (SEC File No.
333-150783)).
|
|
|
10.30***
|
Form of
Employee Restricted Stock Agreement under the TETRA Technologies, Inc.
Amended and Restated 2007 Equity Incentive Compensation Plan (incorporated
by reference to Exhibit 4.15 to the Company’s Registration Statement on
Form S-8 filed on May 9, 2008 (SEC File No.
333-150783)).
|
|
|
10.31***
|
Form of
Non-Employee Director Restricted Stock Agreement under the TETRA
Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation
Plan (incorporated by reference to Exhibit 4.16 to the Company’s
Registration Statement on Form S-8 filed on May 9, 2008 (SEC File No.
333-150783)).
|
|
|
10.32***
|
Transition
Agreement effective as of May 5, 2009, by and among TETRA Technologies,
Inc. and Geoffrey M. Hertel (incorporated by reference to Exhibit 10.1 to
the Company’s Form 8-K filed on May 8, 2009 (SEC File No.
001-13455)).
|
|
|
10.33
|
Form of Senior
Indenture (including form of senior debt security) (incorporated by
reference to Exhibit 4.21 to the Company’s Registration Statement on Form
S-3 filed on November 30, 2009 (SEC File No.
333-163409)).
|
|
|
10.34
|
Form of
Subordinated Indenture (including form of subordinated debt security)
(incorporated by reference to Exhibit 4.22 to the Company’s Registration
Statement on Form S-3 filed on November 30, 2009 (SEC File No.
333-163409)).
|
|
|
21
+
|
Subsidiaries
of the Company.
|
|
|
23.1
+
|
Consent of
Ernst & Young, LLP.
|
|
|
23.2
+
|
Consent of
Ryder Scott Company, L.P.
|
|
|
23.3
+
|
Consent of
DeGolyer and MacNaughton.
|
|
|
31.1
+
|
Certification
Pursuant to Rule 13(a)-14(a) or 15(d)-14(a) of the Exchange Act, As
Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of
2002.
|
|
|
31.2
+
|
Certification
Pursuant to Rule 13(a)-14(a) or 15(d)-14(a) of the Exchange Act, As
Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of
2002.
|
|
|
32.1**
|
Certification
Furnished Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Executive
Officer).
|
|
|
32.2**
|
Certification
Furnished Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Financial
Officer).
|
|
|
99.1
+
|
Report of
Ryder Scott Company, L.P.
|
|
|
99.2
+
|
Report of
DeGolyer and MacNaughton.
|
+ Filed
with this report.
** Furnished
with this report.
*** Management
contract or compensatory plan or arrangement.
65
SIGNATURES
Pursuant to the
requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934,
TETRA Technologies, Inc. has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.
|
TETRA
Technologies, Inc.
|
||
|
Date: March
1, 2010
|
By:
|
/s/ Stuart M.
Brightman
|
|
Stuart M.
Brightman, President & CEO
|
||
Pursuant to the
requirements of the Securities Exchange Act of 1934, this report has been signed
below by the following persons on behalf of the Registrant and in the capacities
and on the dates indicated:
|
S
ignature
|
Title
|
Date
|
|
/s/Ralph S.
Cunningham
|
Chairman
of
|
March 1,
2010
|
|
Ralph S.
Cunningham
|
the Board of
Directors
|
|
|
/s/Stuart M.
Brightman
|
President,
Chief Executive
|
March 1,
2010
|
|
Stuart M.
Brightman
|
Officer and
Director
|
|
|
(Principal
Executive Officer)
|
||
|
/s/Joseph M.
Abell
|
Senior Vice
President and
|
March 1,
2010
|
|
Joseph M.
Abell
|
Chief
Financial Officer
|
|
|
(Principal
Financial Officer)
|
||
|
/s/Ben C.
Chambers
|
Vice
President – Accounting
|
March 1,
2010
|
|
Ben C.
Chambers
|
and
Controller
|
|
|
(Principal
Accounting Officer)
|
||
|
/s/Paul D.
Coombs
|
Director
|
March 1,
2010
|
|
Paul D.
Coombs
|
||
|
/s/Tom H.
Delimitros
|
Director
|
March 1,
2010
|
|
Tom H.
Delimitros
|
||
|
/s/Geoffrey
M. Hertel
|
Director
|
March 1,
2010
|
|
Geoffrey M.
Hertel
|
||
|
/s/Allen T.
McInnes
|
Director
|
March 1,
2010
|
|
Allen T.
McInnes
|
||
|
/s/Kenneth P.
Mitchell
|
Director
|
March 1,
2010
|
|
Kenneth P.
Mitchell
|
||
|
/s/William D.
Sullivan
|
Director
|
March 1,
2010
|
|
William D.
Sullivan
|
|
/s/Kenneth E.
White, Jr.
|
Director
|
March 1,
2010
|
|
Kenneth E.
White, Jr.
|
66
EXHIBIT
INDEX
|
3.1
|
Restated
Certificate of Incorporation of TETRA Technologies, Inc. (incorporated by
reference to Exhibit 3.1 to the Company’s Registration Statement on Form
S-4 filed on December 27, 1995 (SEC File No.
33-80881)).
|
|
3.2
|
Certificate of
Amendment of Restated Certificate of Incorporation of TETRA Technologies,
Inc. (incorporated by reference to Exhibit 3.1 to the Company’s
Registration Statement on Form S-4 filed on December 27, 1995 (SEC File
No. 33-80881)).
|
|
3.3
|
Certificate of
Amendment of Restated Certificate of Incorporation of TETRA Technologies,
Inc. (incorporated by reference to Exhibit 3.1(ii) to the Company’s Annual
Report on Form 10-K for the year ended December 31, 2003 filed on March
15, 2004 (SEC File No. 001-13455)).
|
|
3.4
|
Certificate of
Amendment of Restated Certificate of Incorporation of TETRA Technologies,
Inc. (incorporated by reference to Exhibit 4.4 to the Company’s
Registration Statement on Form S-4 filed on May 25, 2004 (SEC File No.
333-115859)).
|
|
3.5
|
Certificate of
Amendment of Restated Certificate of Incorporation of TETRA Technologies,
Inc. (incorporated by reference to Exhibit 4.5 to the Company’s
Registration Statement on Form S-8 filed on May 4, 2006 (SEC File No.
333-133790)).
|
|
3.6
|
Certificate of
Designation of Series One Junior Participating Preferred Stock of the
Company dated October 27, 1998 (incorporated by reference to Exhibit 2 to
the Company’s Registration Statement on Form 8-A filed on October 28, 1998
(SEC File No. 001-13455)).
|
|
3.7
|
Amended and
Restated Bylaws of TETRA Technologies, Inc. (incorporated by reference to
Exhibit 4.6 to the Company’s Registration Statement on Form S-8 filed on
May 4, 2006 (SEC File No. 333-133790)).
|
|
4.1
|
Rights
Agreement dated October 26, 1998 between the Company and Computershare
Investor Services LLC (as successor in interest to Harris Trust &
Savings Bank), as Rights Agent (incorporated by reference to Exhibit 1 to
the Company’s Registration Statement on Form 8-A filed on October 28, 1998
(SEC File No. 001-13455)).
|
|
4.2
|
Master Note
Purchase Agreement, dated September 27, 2004 by and among TETRA
Technologies, Inc. and Jackson National Life Insurance Company,
Massachusetts Mutual Life Insurance Company, C.M. Life Insurance Company,
Allstate Life Insurance Company, Teachers Insurance and Annuity
Association of America, Pacific Life Insurance Company, the Prudential
Assurance Company Limited (PAC), and Panther CDO II, B.V. (incorporated by
reference to Exhibit 4.1 to the Company’s Form 8-K filed on September 30,
2004 (SEC File No. 001-13455)).
|
|
4.3
|
Form of 5.07%
Senior Notes, Series 2004-A, due September 30, 2011 (incorporated by
reference to Exhibit 4.2 to the Company’s Form 8-K filed on September 30,
2004 (SEC File No. 001-13455)).
|
|
4.4
|
Form of 4.79%
Senior Notes, Series 2004-B, due September 30, 2011 (incorporated by
reference to Exhibit 4.3 to the Company’s Form 8-K filed on September 30,
2004 (SEC File No. 001-13455)).
|
|
4.5
|
Form of
Subsidiary Guaranty dated September 27, 2004, executed by TETRA Applied
Holding Company, TETRA International Incorporated, TETRA Micronutrients,
Inc., TETRA Process Services, Inc., TETRA Thermal, Inc., Maritech
Resources, Inc., Seajay Industries, Inc., TETRA Investment Holding Co.,
Inc., TETRA Financial Services, Inc., Compressco, Inc., Providence Natural
Gas, Inc., TETRA Applied LP, LLC, TETRA Applied GP, LLC, TETRA Production
Testing GP, LLC, TPS Holding Company, LLC, T Production Testing, LLC,
TETRA Real Estate, LLC, TETRA Real Estate, LP, Compressco Testing, L.L.C.,
Compressco Field Services, Inc., TETRA Production Testing Services, L.P.,
and TETRA Applied Technologies, L. P., for the benefit of the holders of
the Notes (incorporated by reference to Exhibit 4.4 to the Company’s Form
8-K filed on September 30, 2004 (SEC File No.
001-13455)).
|
|
4.6
|
First
Supplement to Master Note Purchase Agreement, dated April 18, 2006,
by and among TETRA Technologies, Inc. and Jackson National Life Insurance
Company, Allianz Life Insurance Company of North America, United of Omaha
Life Insurance Company, Mutual of Omaha Insurance Company, CUNA Mutual
Life Insurance Company, CUNA Mutual Insurance Society, CUMIS Insurance
Society, Inc., Members Life Insurance Company, and Modern Woodmen of
America, attaching the form of the 5.90% Senior Notes, Series 2006-A, due
April 30, 2016 as an exhibit thereto (incorporated by reference to Exhibit
4.1 to the Company’s Form 8-K filed on April 20, 2006 (SEC File No.
001-13455)).
|
|
4.7
|
Note Purchase
Agreement, dated April 30, 2008, by and among TETRA Technologies, inc. and
The Prudential Insurance Company of America, Physicians Mutual Insurance
Company, The Lincoln National Life Insurance Company, The Guardian Life
Insurance Company of America, The Guardian Insurance & Annuity
Company, Inc., Massachusetts Mutual Life Insurance Company, Hakone Fund II
LLC, C.M. Life Insurance Company, Pacific Life Insurance Company, United
of Omaha Life Insurance Company, Companion Life Insurance Company, United
World Life Insurance Company, Country Life Insurance Company, The Ohio
National Life Insurance Company and Ohio National Life Assurance
Corporation (incorporated by reference to Exhibit 4.1 to the Company’s
Form 8-K filed on May 5, 2008 (SEC File No.
001-13455)).
|
|
4.8
|
First
Amendment to Rights Agreement dated as of November 6, 2008, by and between
TETRA Technologies, Inc. and Computershare Trust Company, N.A. (as
successor rights agent to Harris Trust and Savings Bank), as Rights Agent
(incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K filed
on November 6, 2008 (SEC File No. 001-13455)).
|
|
4.9
|
Form of 6.30%
Senior Notes, Series 2008-A, due April 30, 2013 (incorporated by reference
to Exhibit 4.2 to the Company’s Form 8-K filed on May 5, 2008 (SEC File
No. 001-13455)).
|
|
4.10
|
Form of 6.56%
Senior Notes, Series 2008-B, due April 30, 2015 (incorporated by reference
to Exhibit 4.3 to the Company’s Form 8-K filed on May 5, 2008 (SEC File
No. 001-13455)).
|
|
4.11
|
Form of
Subsidiary Guarantee dated as of April 30, 2008, executed by Beacon
Resources, LLC, Compressco Field Services, Inc., EPIC Diving and Marine
Services, LLC, Maritech Resources, Inc., TETRA Applied Technologies, LLC,
TETRA International Incorporated, TETRA Process Services, L.C., TETRA
Production Testing Services, LLC, and Maritech Timbalier Bay, LP, for the
benefit of the holders of the Notes (incorporated by reference to Exhibit
4.4 to the Company’s Form 8-K filed on May 5, 2008 (SEC File No.
0001-13455)).
|
|
10.1***
|
1990 Stock
Option Plan, as amended through January 5, 2001 (incorporated by reference
to Exhibit 10.8 to the Company’s Form 10-K for the year ended December 31,
2000 filed on March 30, 2001 (SEC File No. 001-13455)).
|
|
10.2***
|
Director Stock
Option Plan (incorporated by reference to Exhibit 10.9 to the Company’s
Form 10-K for the year ended December 31, 2000 filed on March 30, 2001
(SEC File No. 001-13455)).
|
|
10.3***
|
1998 Director
Stock Option Plan (incorporated by reference to Exhibit 10.10 to the
Company’s Form 10-K for the year ended December 31, 2000 filed on March
23, 2001 (SEC File No. 001-13455)).
|
|
10.4***
|
1996 Stock
Option Plan for Nonexecutive Employees and Consultants (incorporated by
reference to Exhibit 99.1 to the Company’s Registration Statement on Form
S-8 filed on November 19, 1997 (SEC File No.
333-61988)).
|
|
10.5***
|
Letter of
Agreement with Gary C. Hanna, dated March, 2002 (incorporated by reference
to Exhibit 10.8 to the Company’s Form 10-K for the year ended December 31,
2001 filed on March 29, 2002 (SEC File No. 001-13455)).
|
|
10.6***
|
1998 Director
Stock Option Plan (incorporated by reference to Exhibit 10.8 to the
Company’s Form 10-K for the year ended December 31, 2002 filed on March
28, 2003 (SEC File No. 001-13455)).
|
|
10.7
|
Credit
Agreement dated as of September 7, 2004, among TETRA Technologies, Inc.
and certain of its subsidiaries, as borrowers, Bank of America, National
Association, as Administrative Agent, Bank One, NA and Wells Fargo Bank,
N.A., as syndication agents, and Comerica Bank, as documentation agent,
attaching the guaranty dated as of September 7, 2004, by the borrowers, as
guarantors, to the Administrative Agent for the benefit of the lenders
under the Credit Agreement (incorporated by reference to Exhibit 10.1 to
the Company’s Form 8-K filed on September 8, 2004 (SEC File No.
001-13455)).
|
|
10.8***
|
Agreement
between TETRA Technologies, Inc. and Geoffrey M. Hertel, dated February
26, 1993 (incorporated by reference to Exhibit 10.2 to the Company’s Form
8-K filed on January 7, 2005 (SEC File No. 001-13455)).
|
|
10.9***
|
Form of
Incentive Stock Option Agreement, dated as of December 28, 2004
(incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed
on January 7, 2005 SEC File No. 001-13455)).
|
|
10.10***
|
TETRA
Technologies, Inc. 2006 Equity Incentive Compensation Plan (incorporated
by reference to Exhibit 4.12 to the Company’s Registration Statement on
Form S-8 filed on May 4, 2006 (SEC File No.
333-133790)).
|
|
10.11***
|
Forms of
Employee Incentive Stock Option Agreement, Employee Nonqualified Stock
Option Agreement, and Employee Restricted Stock Agreement under the TETRA
Technologies, Inc. 2006 Equity Incentive Compensation Plan (incorporated
by reference to Exhibits 10.1, 10.2, and 10.3 to the Company’s Form 8-K
filed on May 8, 2006 (SEC File No. 001-13455)).
|
|
10.12+***
|
Summary
Description of the Compensation of Non-Employee Directors of TETRA
Technologies, Inc.
|
|
10.13+***
|
Summary
Description of Named Executive Officer Compensation.
|
|
10.14
|
Purchase and
Sale Agreement by and between Pioneer Natural Resources USA, Inc. as
Seller and Maritech Resources, Inc. as Purchaser, dated July 7, 2005
(incorporated by reference to Exhibit 10.1 to the Company’s Form 10-Q
filed on November 9, 2005 (SEC File No. 001-13455), certain portions of
this exhibit have been omitted pursuant to a confidential treatment
request filed with the Securities and Exchange
Commission).
|
|
10.15***
|
Nonqualified
Stock Option Agreement between TETRA Technologies, Inc. and Stuart M.
Brightman, dated April 20, 2005 (incorporated by reference to Exhibit 10.1
to the Company’s Form 8-K filed on April 22, 2005 (SEC File No.
001-13455)).
|
|
10.16***
|
First
Amendment to the TETRA Technologies, Inc. 1998 Director Stock Option Plan
(As Amended Through June 27, 2003), dated December 16, 2005 (incorporated
by reference to Exhibit 10.1 to the Company’s Form 8-K filed on December
22, 2005 (SEC File No. 001-13455)).
|
|
10.17***
|
Form of Stock
Option Agreement under the TETRA Technologies, Inc. 1998 Director Stock
Option Plan (As Amended Through June 27, 2003), as further amended by the
First Amendment to the TETRA Technologies, Inc. 1998 Director Stock Option
Plan (As Amended Through June 27, 2003) (incorporated by reference to
Exhibit 10.2 to the Company’s Form 8-K filed on December 22, 2005 (SEC
File No. 001-13455)).
|
|
10.18
|
Agreement and
Third Amendment to Credit Agreement, dated as of January 20, 2006, among
TETRA Technologies, Inc. and certain of its subsidiaries, as borrowers, JP
Morgan Chase Bank, National Association (successor to Bank One, NA) and
Wells Fargo Bank, N.A., as syndication agents, Comerica Bank, as
documentation agent, Bank of America, National Association, as
administrative agent, and the lenders party thereto (incorporated by
reference to Exhibit 10.1 to the Company’s Form 8-K filed on January 23,
2006 (SEC File No. 001-13455)).
|
|
10.19
|
Credit
Agreement, as amended and restated, dated as of June 27, 2006, among TETRA
Technologies, Inc. and certain of its subsidiaries, as borrowers, JPMorgan
Chase Bank, N.A., as administrative agent, Bank of America, National
Association and Wells Fargo Bank, N.A., as syndication agents, and
Comerica Bank, as documentation agent, and the lenders party thereto
(incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed
on June 30, 2006 (SEC File No. 001-13455)).
|
|
10.20
|
Agreement and
First Amendment to Credit Agreement, dated as of December 15, 2006, among
TETRA Technologies, Inc. and certain of its subsidiaries, as borrowers,
JPMorgan Chase Bank, N.A., as administrative agent, Bank of America,
National Association and Wells Fargo Bank, N.A., as syndication agents,
and Comerica Bank, as documentation agent, and the lenders party thereto
(incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed
on January 10, 2007 (SEC File No. 001-13455)).
|
|
10.21***
|
TETRA
Technologies, Inc. Nonqualified Deferred Compensation Plan (incorporated
by reference to Exhibit 10.9 to the Company’s Form 10-Q filed on August
13, 2002 (SEC File No. 001-13455)).
|
|
10.22***
|
TETRA
Technologies, Inc. Nonqualified Deferred Compensation Plan and The
Executive Excess Plan Adoption Agreement effective on June 30, 2005
(incorporated by reference to Exhibit 10.2 to the Company’s Form 10-Q/A
filed on March 16, 2006 (SEC File No. 001-13455)).
|
|
10.23***
|
TETRA
Technologies, Inc. 2007 Equity Incentive Compensation Plan (incorporated
by reference to Exhibit 4.12 to the Company’s Registration Statement on
Form S-8 filed on May 4, 2007 (SEC File No.
333-142637)).
|
|
10.24***
|
Forms of
Employee Incentive Stock Option Agreement, Employee Nonqualified Stock
Option Agreement, and Employee Restricted Stock Agreement under the TETRA
Technologies, Inc. 2007 Equity Incentive Compensation Plan (incorporated
by reference to Exhibits 4.13, 4.14, and 4.15 to the Company’s
Registration Statement on Form S-8 filed on May 4, 2007 (SEC File No.
333-142637)).
|
|
10.25***
|
TETRA
Technologies, Inc. 401(k) Retirement Plan, as amended and restated
(incorporated by reference to Exhibit 99.1 to the Company’s Registration
Statement on Form S-8 filed on February 22, 2008 (SEC File No.
333-149348)).
|
|
10.26***
|
Employee
Restricted Stock Agreement between TETRA Technologies, Inc. and Philip N.
Longorio, dated February 22, 2008 (incorporated by reference to Exhibit
4.12 to the Company’s Registration Statement on Form S-8 filed on February
22, 2008 (SEC File No. 333-149347)).
|
|
10.27***
|
TETRA
Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation
Plan (incorporated by reference to Exhibit 4.12 to the Company’s
Registration Statement on Form S-8 filed on May 9, 2008 (SEC File No.
333-150783)).
|
|
10.28***
|
Form of
Employee Incentive Stock Option Agreement under the TETRA Technologies,
Inc. Amended and Restated 2007 Equity Incentive Compensation Plan
(incorporated by reference to Exhibit 4.13 to the Company’s Registration
Statement on Form S-8 filed on May 9, 2008 (SEC File No.
333-150783)).
|
|
10.29***
|
Form of
Employee Nonqualified Stock Option Agreement under the TETRA Technologies,
Inc. Amended and Restated 2007 Equity Incentive Compensation Plan
(incorporated by reference to Exhibit 4.14 to the Company’s Registration
Statement on Form S-8 filed on May 9, 2008 (SEC File No.
333-150783)).
|
|
10.30***
|
Form of
Employee Restricted Stock Agreement under the TETRA Technologies, Inc.
Amended and Restated 2007 Equity Incentive Compensation Plan (incorporated
by reference to Exhibit 4.15 to the Company’s Registration Statement on
Form S-8 filed on May 9, 2008 (SEC File No.
333-150783)).
|
|
10.31***
|
Form of
Non-Employee Director Restricted Stock Agreement under the TETRA
Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation
Plan (incorporated by reference to Exhibit 4.16 to the Company’s
Registration Statement on Form S-8 filed on May 9, 2008 (SEC File No.
333-150783)).
|
|
10.32***
|
Transition
Agreement effective as of May 5, 2009, by and among TETRA Technologies,
Inc. and Geoffrey M. Hertel (incorporated by reference to Exhibit 10.1 to
the Company’s Form 8-K filed on May 8, 2009 (SEC File No.
001-13455)).
|
|
10.33
|
Form of Senior
Indenture (including form of senior debt security) (incorporated by
reference to Exhibit 4.21 to the Company’s Registration Statement on Form
S-3 filed on November 30, 2009 (SEC File No.
333-163409)).
|
|
10.34
|
Form of
Subordinated Indenture (including form of subordinated debt security)
(incorporated by reference to Exhibit 4.22 to the Company’s Registration
Statement on Form S-3 filed on November 30, 2009 (SEC File No.
333-163409)).
|
|
21
+
|
Subsidiaries
of the Company.
|
|
23.1
+
|
Consent of
Ernst & Young, LLP.
|
|
23.2
+
|
Consent of
Ryder Scott Company, L.P.
|
|
23.3
+
|
Consent of
DeGolyer and McNaughton.
|
|
31.1
+
|
Certification
Pursuant to Rule 13(a)-14(a) or 15(d)-14(a) of the Exchange Act, As
Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of
2002.
|
|
31.2
+
|
Certification
Pursuant to Rule 13(a)-14(a) or 15(d)-14(a) of the Exchange Act, As
Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of
2002.
|
|
32.1**
|
Certification
Furnished Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Executive
Officer).
|
|
32.2**
|
Certification
Furnished Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002 (Chief Financial
Officer).
|
|
99.1
+
|
Report of
Ryder Scott Company, L.P.
|
|
99.2
+
|
Report of
DeGolyer and MacNaughton.
|
+ Filed
with this report.
** Furnished
with this report.
*** Management
contract or compensatory plan or arrangement.
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors
and Stockholders of
TETRA Technologies,
Inc.
We have audited the accompanying consolidated
balance sheets of TETRA Technologies, Inc. and subsidiaries as of December 31,
2009 and 2008, and the related consolidated statements of operations,
stockholders' equity, and cash flows for each of the three years in the period
ended December 31, 2009. These financial statements are the responsibility of
the Company’s management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with the
standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements
referred to above present fairly, in all material respects, the consolidated
financial position of TETRA Technologies, Inc. and subsidiaries at December 31,
2009 and 2008, and the consolidated results of their operations and their cash
flows for each of the three years in the period ended December 31, 2009, in
conformity with U.S. generally accepted accounting principles.
As discussed in Notes B and R to the
consolidated financial statements, in 2009, the Company adopted SEC Release
33-8995 and the amendments to ASC Topic 932, “Extractive Industries – Oil and
Gas,” resulting from ASU 2010-03 (collectively, the Modernization
Rules).
We have also audited, in accordance with the
standards of the Public Company Accounting Oversight Board (United States),
TETRA Technologies, Inc.’s internal control over financial reporting as of
December 31, 2009, based on criteria established in Internal Control –
Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission and our report dated March 1, 2010, expressed an unqualified
opinion thereon.
/s/ERNST & YOUNG LLP
Houston,
Texas
March 1,
2010
F-1
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors
and Stockholders of
TETRA Technologies,
Inc.
We have audited TETRA Technologies, Inc. and
subsidiaries’ internal control over financial reporting as of December 31, 2009,
based on criteria established in Internal Control – Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission (the
COSO criteria). TETRA Technologies, Inc. and subsidiaries’ management is
responsible for maintaining effective internal control over financial reporting,
and for its assessment of the effectiveness of internal control over financial
reporting included in the accompanying Management’s Report on Internal Control
over Financial Reporting. Our responsibility is to express an opinion on the
company’s internal control over financial reporting based on our
audit.
We conducted our audit in accordance with the
standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether effective internal control over financial reporting was
maintained in all material respects. Our audit included obtaining an
understanding of internal control over financial reporting, assessing the risk
that a material weakness exists, testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk, and performing
such other procedures as we considered necessary in the circumstances. We
believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial
reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements
for external purposes in accordance with generally accepted accounting
principles. A company’s internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance of records that, in
reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles, and that
receipts and expenditures of the company are being made only in accordance with
authorizations of management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the company’s assets that could have a
material effect on the financial statements.
Because of its inherent limitations, internal
control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to
the risk that controls may become inadequate because of changes in conditions,
or that the degree of compliance with the policies or procedures may
deteriorate.
In our opinion, TETRA Technologies, Inc. and
subsidiaries maintained, in all material respects, effective internal control
over financial reporting as of December 31, 2009, based on the COSO
criteria.
We also have audited, in accordance with the
standards of the Public Company Accounting Oversight Board (United States), the
consolidated balance sheets of TETRA Technologies, Inc. and subsidiaries as of
December 31, 2009 and 2008, and the related consolidated statements of
operations, stockholders’ equity and cash flows for each of the three years in
the period ended December 31, 2009, and our report dated March 1, 2010,
expressed an unqualified opinion thereon.
/s/ERNST & YOUNG LLP
Houston,
Texas
March 1,
2010
F-2
TETRA
Technologies, Inc. and Subsidiaries
Consolidated
Balance Sheets
(In
Thousands)
|
December
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
ASSETS
|
||||||||
|
Current
assets:
|
||||||||
|
Cash
and cash equivalents
|
$ | 33,394 | $ | 3,882 | ||||
|
Restricted
cash
|
266 | 2,150 | ||||||
|
Accounts
receivable, net of allowance for doubtful accounts
|
||||||||
|
of
$5,007 in 2009 and $3,198 in 2008
|
181,038 | 225,491 | ||||||
|
Inventories
|
122,274 | 117,731 | ||||||
|
Derivative
assets
|
19,926 | 38,052 | ||||||
|
Prepaid
expenses and other current assets
|
33,905 | 47,768 | ||||||
|
Assets
of discontinued operations
|
15 | 239 | ||||||
|
Total
current assets
|
390,818 | 435,313 | ||||||
|
Property,
plant, and equipment:
|
||||||||
|
Land
and building
|
77,246 | 23,730 | ||||||
|
Machinery
and equipment
|
458,675 | 463,788 | ||||||
|
Automobiles
and trucks
|
42,432 | 43,047 | ||||||
|
Chemical
plants
|
94,767 | 46,121 | ||||||
|
Oil
and gas producing assets (successful efforts method)
|
676,692 | 697,754 | ||||||
|
Construction
in progress
|
95,470 | 118,103 | ||||||
| 1,445,282 | 1,392,543 | |||||||
|
Less
accumulated depreciation and depletion
|
(628,908 | ) | (585,077 | ) | ||||
|
Net
property, plant and equipment
|
816,374 | 807,466 | ||||||
|
Other
assets:
|
||||||||
|
Goodwill
|
99,005 | 82,525 | ||||||
|
Patents,
trademarks, and other intangible assets, net of
|
||||||||
|
accumulated
amortization of $18,997 in 2009 and $15,611 in 2008
|
13,198 | 16,549 | ||||||
|
Derivative
assets
|
- | 39,098 | ||||||
|
Deferred
tax assets
|
1,342 | 1,699 | ||||||
|
Other
assets
|
26,862 | 29,974 | ||||||
|
Total
other assets
|
140,407 | 169,845 | ||||||
| $ | 1,347,599 | $ | 1,412,624 | |||||
See Notes to
Consolidated Financial Statements
F-3
TETRA
Technologies, Inc. and Subsidiaries
Consolidated
Balance Sheets
(In
Thousands, Except Per Share Amounts)
|
December
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
LIABILITIES
AND STOCKHOLDERS' EQUITY
|
||||||||
|
Current
liabilities:
|
||||||||
|
Trade
accounts payable
|
$ | 57,418 | $ | 76,973 | ||||
|
Accrued
liabilities
|
84,638 | 86,659 | ||||||
|
Decommissioning
and other asset retirement obligations, current
|
77,891 | 45,954 | ||||||
|
Deferred
tax liabilities
|
19,893 | 2,882 | ||||||
|
Derivative
liabilities
|
2,618 | - | ||||||
|
Liabilities
of discontinued operations
|
17 | 13 | ||||||
|
Total
current liabilities
|
242,475 | 212,481 | ||||||
|
Long-term
debt, net
|
310,132 | 406,840 | ||||||
|
Deferred
income taxes
|
56,125 | 64,911 | ||||||
|
Decommissioning
and other asset retirement obligations, net
|
146,219 | 202,771 | ||||||
|
Other
liabilities
|
16,154 | 9,800 | ||||||
|
Total
long-term and other liabilities
|
528,630 | 684,322 | ||||||
|
Commitments
and contingencies
|
||||||||
|
Stockholders'
equity:
|
||||||||
|
Common
stock, par value $.01 per share; 100,000,000 shares
|
||||||||
|
authorized;
77,039,628 shares issued at December 31, 2009
|
||||||||
|
and
76,841,424 shares issued at December 31, 2008
|
770 | 768 | ||||||
|
Additional
paid-in capital
|
193,718 | 186,318 | ||||||
|
Treasury
stock, at cost; 1,497,346 shares held at December 31,
|
||||||||
|
2009
and 1,582,465 shares held at December 31, 2008
|
(8,310 | ) | (8,843 | ) | ||||
|
Accumulated
other comprehensive income
|
26,822 | 42,888 | ||||||
|
Retained
earnings
|
363,494 | 294,690 | ||||||
|
Total
stockholders' equity
|
576,494 | 515,821 | ||||||
| $ | 1,347,599 | $ | 1,412,624 | |||||
See Notes to
Consolidated Financial Statements
F-4
TETRA
Technologies, Inc. and Subsidiaries
Consolidated
Statements of Operations
(In
Thousands, Except Per Share Amounts)
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Revenues:
|
||||||||||||
|
Product
sales
|
$ | 350,005 | $ | 447,341 | $ | 457,238 | ||||||
|
Services
and rentals
|
528,872 | 561,724 | 525,245 | |||||||||
|
Total
revenues
|
878,877 | 1,009,065 | 982,483 | |||||||||
|
Cost of
revenues:
|
||||||||||||
|
Cost
of product sales
|
237,911 | 283,194 | 304,976 | |||||||||
|
Cost
of services and rentals
|
310,943 | 364,275 | 362,745 | |||||||||
|
Gain
on insurance recoveries
|
(45,391 | ) | (697 | ) | (3,245 | ) | ||||||
|
Depreciation,
depletion, amortization, and accretion
|
149,326 | 158,893 | 129,844 | |||||||||
|
Impairments
of long-lived assets
|
12,991 | 51,399 | 71,780 | |||||||||
|
Total
cost of revenues
|
665,780 | 857,064 | 866,100 | |||||||||
|
Gross
profit
|
213,097 | 152,001 | 116,383 | |||||||||
|
General and
administrative expense
|
100,832 | 104,949 | 99,871 | |||||||||
|
Impairment of
goodwill
|
- | 47,073 | - | |||||||||
|
Operating
income (loss)
|
112,265 | (21 | ) | 16,512 | ||||||||
|
Interest
expense, net
|
12,790 | 16,778 | 17,155 | |||||||||
|
Other income,
net
|
5,895 | 12,884 | 2,805 | |||||||||
|
Income (loss)
before taxes and discontinued operations
|
105,370 | (3,915 | ) | 2,162 | ||||||||
|
Provision for
income taxes
|
36,563 | 5,740 | 941 | |||||||||
|
Income (loss)
before discontinued operations
|
68,807 | (9,655 | ) | 1,221 | ||||||||
|
Discontinued
operations:
|
||||||||||||
|
Income
(loss) from discontinued operations, net of taxes
|
(426 | ) | (2,481 | ) | 1,723 | |||||||
|
Gain
on disposal of discontinued operations, net of taxes
|
423 | - | 25,827 | |||||||||
|
Income
(loss) from discontinued operations
|
(3 | ) | (2,481 | ) | 27,550 | |||||||
|
Net
income (loss)
|
$ | 68,804 | $ | (12,136 | ) | $ | 28,771 | |||||
|
Basic net
income (loss) per common share:
|
||||||||||||
|
Income
(loss) before discontinued operations
|
$ | 0.92 | $ | (0.13 | ) | $ | 0.02 | |||||
|
Income
(loss) from discontinued operations
|
(0.01 | ) | (0.03 | ) | 0.02 | |||||||
|
Gain
on disposal of discontinued operations
|
0.01 | - | 0.35 | |||||||||
|
Net
income (loss)
|
$ | 0.92 | $ | (0.16 | ) | $ | 0.39 | |||||
|
Average
shares outstanding
|
75,045 | 74,519 | 73,573 | |||||||||
|
Diluted net
income (loss) per common share:
|
||||||||||||
|
Income
(loss) before discontinued operations
|
$ | 0.91 | $ | (0.13 | ) | $ | 0.02 | |||||
|
Income
(loss) from discontinued operations
|
(0.01 | ) | (0.03 | ) | 0.02 | |||||||
|
Gain
on disposal of discontinued operations
|
0.01 | - | 0.34 | |||||||||
|
Net
income (loss)
|
$ | 0.91 | $ | (0.16 | ) | $ | 0.38 | |||||
|
Average
diluted shares outstanding
|
75,722 | 74,519 | 75,921 | |||||||||
See Notes to
Consolidated Financial Statements
F-5
TETRA
Technologies, Inc. and Subsidiaries
Consolidated
Statements of Stockholders’ Equity
(In
Thousands, Except Share Information)
|
Accumulated
Other
|
|||||||||||||||||||||||||||||||
|
Outstanding
|
Treasury
|
Common
|
Additional
|
Comprehensive
Income (Loss)
|
Total
|
||||||||||||||||||||||||||
|
Common
|
Shares
|
Stock
|
Paid-In
|
Treasury
|
Retained
|
Derivative
|
Currency
|
Stockholders'
|
|||||||||||||||||||||||
|
Shares
|
Held
|
Par
Value
|
Capital
|
Stock
|
Earnings
|
Instruments
|
Translation
|
Equity
|
|||||||||||||||||||||||
|
Balance at
December 31, 2006
|
71,931,428 | 1,946,039 | $ | 739 | $ | 147,178 | $ | (10,524 | ) | $ | 278,112 | $ | 2,883 | $ | 1,992 | $ | 420,380 | ||||||||||||||
|
Net income for
2007
|
28,771 | 28,771 | |||||||||||||||||||||||||||||
|
Translation
adjustment, net of
|
|||||||||||||||||||||||||||||||
|
taxes
of $1,381
|
4,870 | 4,870 | |||||||||||||||||||||||||||||
|
Net change in
derivative fair value,
|
|||||||||||||||||||||||||||||||
|
net
of taxes of $21,887
|
(37,110 | ) | (37,110 | ) | |||||||||||||||||||||||||||
|
Reclassification
of derivative fair value
|
|||||||||||||||||||||||||||||||
|
into
earnings, net of taxes of $809
|
1,366 | 1,366 | |||||||||||||||||||||||||||||
|
Comprehensive
income
|
(2,103 | ) | |||||||||||||||||||||||||||||
|
Impact of
adoption of FIN No. 48
|
(57 | ) | (57 | ) | |||||||||||||||||||||||||||
|
Exercise of
common stock options
|
2,208,371 | (422,861 | ) | 20 | 9,954 | 2,192 | 12,166 | ||||||||||||||||||||||||
|
Grants of
restricted stock, net
|
230,966 | 27,784 | (73 | ) | (73 | ) | |||||||||||||||||||||||||
|
Stock option
expense
|
4,416 | 4,416 | |||||||||||||||||||||||||||||
|
Tax benefit
upon exercise of certain
|
|||||||||||||||||||||||||||||||
|
nonqualified
and incentive options
|
13,190 | 13,190 | |||||||||||||||||||||||||||||
|
Balance at
December 31, 2007
|
74,370,765 | 1,550,962 | $ | 759 | $ | 174,738 | $ | (8,405 | ) | $ | 306,826 | $ | (32,861 | ) | $ | 6,862 | $ | 447,919 | |||||||||||||
|
Net loss for
2008
|
(12,136 | ) | (12,136 | ) | |||||||||||||||||||||||||||
|
Translation
adjustment, net of
|
|||||||||||||||||||||||||||||||
|
taxes
of $387
|
(11,381 | ) | (11,381 | ) | |||||||||||||||||||||||||||
|
Net change in
derivative fair value,
|
|||||||||||||||||||||||||||||||
|
net
of taxes of $26,449
|
44,650 | 44,650 | |||||||||||||||||||||||||||||
|
Reclassification
of derivative fair value
|
|||||||||||||||||||||||||||||||
|
into
earnings, net of taxes of $21,099
|
35,618 | 35,618 | |||||||||||||||||||||||||||||
|
Comprehensive
income
|
56,751 | ||||||||||||||||||||||||||||||
|
Exercise of
common stock options
|
722,992 | (18,696 | ) | 7 | 4,170 | (296 | ) | 3,881 | |||||||||||||||||||||||
|
Grants of
restricted stock, net
|
165,202 | 50,199 | 2 | (142 | ) | (140 | ) | ||||||||||||||||||||||||
|
Stock option
expense
|
5,898 | 5,898 | |||||||||||||||||||||||||||||
|
Tax benefit
upon exercise of certain
|
|||||||||||||||||||||||||||||||
|
nonqualified
and incentive options
|
1,512 | 1,512 | |||||||||||||||||||||||||||||
|
Balance at
December 31, 2008
|
75,258,959 | 1,582,465 | $ | 768 | $ | 186,318 | $ | (8,843 | ) | $ | 294,690 | $ | 47,407 | $ | (4,519 | ) | $ | 515,821 | |||||||||||||
|
Net income for
2009
|
68,804 | 68,804 | |||||||||||||||||||||||||||||
|
Translation
adjustment, net of
|
|||||||||||||||||||||||||||||||
|
taxes
of $1,564
|
7,869 | 7,869 | |||||||||||||||||||||||||||||
|
Net change in
derivative fair value,
|
|||||||||||||||||||||||||||||||
|
net
of taxes of $3,339
|
5,601 | 5,601 | |||||||||||||||||||||||||||||
|
Reclassification
of derivative fair value
|
|||||||||||||||||||||||||||||||
|
into
earnings, net of taxes of $(17,496)
|
(29,536 | ) | (29,536 | ) | |||||||||||||||||||||||||||
|
Comprehensive
income
|
52,738 | ||||||||||||||||||||||||||||||
|
Exercise of
common stock options
|
204,651 | (106,000 | ) | 2 | 632 | 588 | 1,222 | ||||||||||||||||||||||||
|
Grants of
restricted stock, net
|
78,672 | 20,881 | (55 | ) | (55 | ) | |||||||||||||||||||||||||
|
Stock option
expense
|
6,662 | 6,662 | |||||||||||||||||||||||||||||
|
Minority
interest
|
(141 | ) | (141 | ) | |||||||||||||||||||||||||||
|
Tax benefit
upon exercise of certain
|
|||||||||||||||||||||||||||||||
|
nonqualified
and incentive options
|
247 | 247 | |||||||||||||||||||||||||||||
|
Balance at
December 31, 2009
|
75,542,282 | 1,497,346 | $ | 770 | $ | 193,718 | $ | (8,310 | ) | $ | 363,494 | $ | 23,472 | $ | 3,350 | $ | 576,494 | ||||||||||||||
See Notes to
Consolidated Financial Statements
F-6
TETRA Technologies, Inc. and Subsidiaries
Consolidated
Statements of Cash Flows
(In
Thousands)
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Operating
activities:
|
||||||||||||
|
Net
income (loss)
|
$ | 68,804 | $ | (12,136 | ) | $ | 28,771 | |||||
|
Reconciliation of net income (loss) to cash provided by operating
activities:
|
||||||||||||
|
Depreciation,
depletion, amortization, and accretion
|
149,326 | 158,893 | 129,844 | |||||||||
|
Impairment
of goodwill
|
- | 47,073 | - | |||||||||
|
Impairments
of long-lived assets
|
19,531 | 51,399 | 71,780 | |||||||||
|
Provision
(benefit) for deferred income taxes
|
21,204 | (1,067 | ) | 674 | ||||||||
|
Stock
compensation expense
|
6,662 | 5,898 | 4,416 | |||||||||
|
Provision
for doubtful accounts
|
3,393 | 3,082 | 1,459 | |||||||||
|
Proceeds
from sale of derivatives
|
23,060 | - | - | |||||||||
|
Gain
on sale of property, plant, and equipment
|
(7,333 | ) | (3,347 | ) | (4,974 | ) | ||||||
|
Other
non-cash charges and credits
|
25,043 | (212 | ) | 26,043 | ||||||||
|
Excess
tax benefit from exercise of stock options
|
(247 | ) | (1,510 | ) | (13,189 | ) | ||||||
|
Equity
in (earnings) loss of unconsolidated subsidiary
|
(510 | ) | (554 | ) | 1,063 | |||||||
|
Changes in operating assets and liabilities, net of assets
acquired:
|
||||||||||||
|
Accounts
receivable
|
62,364 | (3,940 | ) | (5,346 | ) | |||||||
|
Inventories
|
(4,628 | ) | (1,397 | ) | 2,626 | |||||||
|
Prepaid
expenses and other current assets
|
13,611 | (18,913 | ) | (5,152 | ) | |||||||
|
Trade
accounts payable and accrued expenses
|
(30,622 | ) | (14,058 | ) | 27,936 | |||||||
|
Decommissioning
liabilities
|
(79,471 | ) | (19,430 | ) | (32,919 | ) | ||||||
|
Operating
activities of discontinued operations
|
228 | 3,344 | (22,993 | ) | ||||||||
|
Other
|
1,900 | (3,314 | ) | (1,000 | ) | |||||||
|
Net
cash provided by operating activities
|
272,315 | 189,811 | 209,039 | |||||||||
|
Investing
activities:
|
||||||||||||
|
Purchases
of property, plant, and equipment
|
(151,773 | ) | (262,099 | ) | (276,074 | ) | ||||||
|
Business
combinations, net of cash acquired
|
(18,105 | ) | - | (14,479 | ) | |||||||
|
Proceeds
from sale of property, plant, and equipment
|
15,925 | 380 | 2,582 | |||||||||
|
Other
investing activities
|
4,254 | 264 | (2,621 | ) | ||||||||
|
Investing
activities of discontinued operations
|
- | - | 55,414 | |||||||||
|
Net
cash used in investing activities
|
(149,699 | ) | (261,455 | ) | (235,178 | ) | ||||||
|
Financing
activities:
|
||||||||||||
|
Proceeds
from long-term debt
|
197,900 | 182,450 | 116,930 | |||||||||
|
Principal
payments on long-term debt
|
(295,034 | ) | (131,428 | ) | (100,937 | ) | ||||||
|
Excess
tax benefit from exercise of stock options
|
247 | 1,510 | 13,189 | |||||||||
|
Proceeds
from sale of common stock and exercise of stock options
|
1,165 | 4,749 | 12,087 | |||||||||
|
Net
cash provided by (used in) financing activities
|
(95,722 | ) | 57,281 | 41,269 | ||||||||
|
Effect
of exchange rate changes on cash
|
2,618 | (3,588 | ) | 1,168 | ||||||||
|
Increase
(decrease) in cash and cash equivalents
|
29,512 | (17,951 | ) | 16,298 | ||||||||
|
Cash and cash
equivalents at beginning of period
|
3,882 | 21,833 | 5,535 | |||||||||
|
Cash and cash
equivalents at end of period
|
$ | 33,394 | $ | 3,882 | $ | 21,833 | ||||||
|
Supplemental
cash flow information:
|
||||||||||||
|
Interest
paid
|
$ | 19,940 | $ | 19,488 | $ | 18,640 | ||||||
|
Taxes
paid
|
11,505 | 9,420 | 12,184 | |||||||||
|
Supplemental
disclosure of non-cash investing and financing activities:
|
||||||||||||
|
Oil
and gas properties acquired through assumption of
|
||||||||||||
|
decommissioning
liabilities
|
$ | - | $ | 22,236 | $ | 24,759 | ||||||
|
Adjustment
of fair value of decommissioning liabilities
|
||||||||||||
|
capitalized
to oil and gas properties
|
$ | 23,705 | $ | 32,511 | $ | 71,683 | ||||||
See Notes to
Consolidated Financial Statements
F-7
TETRA
TECHNOLOGIES, INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
December
31, 2009
NOTE
A — ORGANIZATION AND OPERATIONS
We
are a geographically diversified oil and gas services company focused on
completion fluids and other products, production testing, wellhead compression,
and selected offshore services including well plugging and abandonment,
decommissioning, and diving, with a concentrated domestic exploration and
production business. We were incorporated in Delaware in 1981. We are composed
of three divisions – Fluids, Offshore, and Production Enhancement. Unless the
context requires otherwise, when we refer to “we,” “us,” and “our,” we are
describing TETRA Technologies, Inc. and its consolidated subsidiaries on a
consolidated basis.
Our Fluids Division
manufactures and markets clear brine fluids, additives, and other associated
products and services to the oil and gas industry for use in well drilling,
completion, and workover operations, both in the United States and in certain
regions of Latin America, Europe, Asia, and Africa. The Division also markets
liquid and dry calcium chloride manufactured at its production facilities to a
variety of markets outside the energy industry.
Our Offshore
Division consists of two operating segments: Offshore Services and Maritech. The
Offshore Services segment provides (1) downhole and subsea services such as
plugging and abandonment, workover, and wireline services, (2) construction and
decommissioning services, including hurricane damage remediation, utilizing our
heavy lift barges and cutting technologies in the construction or
decommissioning of offshore oil and gas production platforms and pipelines, and
(3) diving services involving conventional and saturated air diving and the
operation of several dive support vessels.
The Maritech
segment consists of our Maritech Resources, Inc. (Maritech) subsidiary, which,
with its subsidiaries, is an oil and gas exploration and production company
focused in the offshore and onshore U.S. Gulf Coast region. Maritech
periodically acquires oil and gas properties in order to replenish or expand its
production operations and to provide additional development and exploitation
opportunities. The Offshore Division’s Offshore Services segment performs a
significant portion of the well abandonment and decommissioning services
required by Maritech.
Our Production
Enhancement Division consists of two operating segments: Production Testing and
Compressco. The Production Testing segment provides production testing services
in many of the major oil and gas basins in the United States, as well as to
onshore basins in Mexico, Brazil, Northern Africa, the Middle East, and other
international markets.
The Compressco
segment provides wellhead compression-based production enhancement services
throughout many of the onshore producing regions of the United States, as well
as basins in Canada, Mexico, South America, Europe, Asia, and other
international locations. These compression services can improve the value of
natural gas and oil wells by increasing daily production and total recoverable
reserves.
NOTE B — SUMMARY OF SIGNIFICANT
ACCOUNTING POLICIES
Principles
of Consolidation
The consolidated financial statements include
the accounts of our wholly owned subsidiaries. Investments in unconsolidated
joint ventures in which we participate are accounted for using the equity
method. Our interests in oil and gas properties are proportionately
consolidated. All significant intercompany accounts and transactions have been
eliminated in consolidation.
Use
of Estimates
The preparation of financial statements in
conformity with generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclose contingent assets and liabilities at the date of the
financial statements and the reported amounts of revenues and expenses during
the reporting period. Actual results could differ from those
estimates.
F-8
Reclassifications
We have accounted for the discontinuance or
disposal of certain businesses as discontinued operations and have reclassified
prior period financial statements to exclude these businesses from continuing
operations. See Note C – Discontinued Operations, for a further discussion of
the discontinuance of these businesses and the impact of prior period’s
reclassifications on our consolidated financial statements.
Certain other previously reported financial
information has also been reclassified to conform to the current year's
presentation.
Cash
Equivalents
We consider all highly liquid investments, with
a maturity of three months or less when purchased, to be cash
equivalents.
Restricted
Cash
Restricted cash
reflected on our balance sheets as of December 31, 2009 and 2008 includes
escrowed funds related to agreed repairs to be expended at one of our former
Fluids Division facility locations. In addition, restricted cash as of December
31, 2008 includes a third party’s proportionate obligation in the plugging and
abandonment of a particular oil and gas property operated by our Maritech
subsidiary. This cash became unrestricted at the time the associated plugging
and abandonment project was completed during 2009.
Financial
Instruments
Financial instruments that subject us to
concentrations of credit risk consist principally of trade receivables with
companies in the energy industry. Our policy is to evaluate, prior to providing
goods or services, each customer's financial condition and to determine the
amount of open credit to be extended. We generally require appropriate,
additional collateral as security for credit amounts in excess of approved
limits. Our customers consist primarily of major, well-established oil and gas
producers and independent oil and gas companies. Our risk management activities
currently involve the use of derivative financial instruments, such as oil and
gas swap contracts, to hedge the impact of commodity market price risk exposures
related to a portion of our oil and gas production cash flow.
To the extent we have any outstanding balance
under our variable rate bank credit facility, we may face market risk exposure
related to changes in applicable interest rates. Although we have no interest
rate swap contracts outstanding to hedge this risk exposure, we have entered
into certain fixed interest rate notes, which are scheduled to mature at various
dates from 2011 through 2016 and which mitigate this risk on our total
outstanding borrowings.
Allowances for Doubtful
Accounts
Allowances for doubtful accounts are determined
on a specific identification basis when we believe that the collection of
specific amounts owed to us is not probable.
Inventories
Inventories are stated at the lower of cost or
market value. Cost is determined using the weighted average method. Significant
components of inventories as of December 31, 2009 and 2008 are as
follows:
|
December
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(In
Thousands)
|
||||||||
|
Finished
goods
|
$ | 88,704 | $ | 85,908 | ||||
|
Raw
materials
|
3,436 | 4,106 | ||||||
|
Parts and
supplies
|
26,060 | 26,531 | ||||||
|
Work in
progress
|
4,074 | 1,186 | ||||||
|
Total
inventories
|
$ | 122,274 | $ | 117,731 | ||||
F-9
Finished goods
inventories include, in addition to newly manufactured clear brine fluids,
recycled brines that are repurchased from certain of our customers. Recycled
brines are recorded at cost, using the weighted average method.
Property,
Plant, and Equipment
Property, plant, and equipment are stated at
the cost of assets acquired. Expenditures that increase the useful lives of
assets are capitalized. The cost of repairs and maintenance is charged to
operations as incurred. For financial reporting purposes, we generally provide
for depreciation using the straight-line method over the estimated useful lives
of assets, which are as follows:
|
Buildings
|
15 – 25
years
|
|
Machinery,
vessels, and equipment
|
3 – 15
years
|
|
Automobiles
and trucks
|
4
years
|
|
Chemical
plants
|
15 – 30
years
|
Leasehold improvements are depreciated over the
shorter of the remaining term of the associated lease or its useful life.
Depreciation and depletion expense, excluding oil and gas impairments and dry
hole costs, for the years ended December 31, 2009, 2008, and 2007 was $137.8
million, $138.0 million, and $118.6 million, respectively.
Interest capitalized for the years ended
December 31, 2009, 2008, and 2007 was $6.8 million, $3.2 million, and $1.4
million, respectively.
Oil
and Gas Properties
Maritech conducts oil and gas exploration,
development, and production activities. Maritech periodically purchases oil and
gas properties and assumes the related well abandonment and decommissioning
liabilities (referred to as decommissioning liabilities). We follow the
successful efforts method of accounting for our oil and gas operations. Under
the successful efforts method, the costs of successful exploratory wells and
leases are capitalized. Costs incurred to drill and equip development wells,
including unsuccessful development wells, are capitalized. Other costs such as
geological and geophysical costs, drilling costs of unsuccessful exploratory
wells, and all internal costs are expensed. Maritech’s property purchases are
recorded at the fair value of our working interest share of decommissioning
liabilities assumed, plus or minus any cash or other consideration paid or
received at the time of closing the transaction. All capitalized costs are
accumulated and recorded separately for each field and allocated to leasehold
costs and well costs. Leasehold costs are depleted on a unit of production
method based on the estimated remaining equivalent proved oil and gas reserves
of each field. Well costs are depleted on a unit of production method based on
the estimated remaining equivalent proved developed oil and gas reserves of each
field.
Intangible
Assets other than Goodwill
Patents, trademarks, and other intangible
assets are recorded on the basis of cost and are amortized on a straight-line
basis over their estimated useful lives, ranging from 3 to 20 years. During
2007, as a part of certain acquisitions consummated during the year, we acquired
intangible assets having a fair value of approximately $2.4 million with
estimated useful lives ranging from two to six years (having a weighted average
useful life of 5.5 years). Amortization expense of patents, trademarks, and
other intangible assets was $3.6 million, $4.5 million, and $3.8 million for the
twelve months ended December 31, 2009, 2008, and 2007, respectively, and is
included in operating income. The estimated future annual amortization expense
of patents, trademarks, and other intangible assets is $2.3 million for 2010,
$2.2 million for 2011, $2.1 million for 2012, $2.0 million for 2013, and $0.7
million for 2014.
Goodwill
Goodwill represents the excess of cost over the
fair value of the net assets of businesses acquired in purchase transactions. We
perform a goodwill impairment test on an annual basis or whenever indicators of
impairment are present. We perform the annual test of goodwill impairment
following the fourth quarter of each year. The goodwill impairment test consists
of a two-step accounting test performed on a reporting unit basis. For purposes
of this impairment test, the reporting units are our five reporting segments:
Fluids, Offshore Services, Maritech, Production Testing, and Compressco. The
first step of the impairment test is to compare the estimated fair value of any
reporting units that have recorded goodwill with the recorded net
F-10
book value
(including goodwill) of the reporting unit. If the estimated fair value of the
reporting unit is higher than the recorded net book value, no impairment is
deemed to exist and no further testing is required. If, however, the estimated
fair value of the reporting unit is below the recorded net book value, then a
second step must be performed to determine the goodwill impairment required, if
any. In this second step, the estimated fair value from the first step is used
as the purchase price in a hypothetical acquisition of the reporting unit.
Purchase business combination accounting rules are followed to determine a
hypothetical purchase price allocation to the reporting unit’s assets and
liabilities. The residual amount of goodwill that results from this hypothetical
purchase price allocation is compared to the recorded amount of goodwill for the
reporting unit, and the recorded amount is written down to the hypothetical
amount, if lower.
Because quoted market prices for our reporting
units are not available, management must apply judgment in determining the
estimated fair value of these reporting units for purposes of performing the
goodwill impairment test. Management uses all available information to make
these fair value determinations, including the present value of expected future
cash flows using discount rates commensurate with the risks involved in the
assets. The resultant fair values calculated for the reporting units are then
compared to observable metrics for other companies in our industry, or on
mergers and acquisitions in our industry, to determine whether those valuations,
in our judgment, appear reasonable. We have estimated the fair value of each
reporting unit based upon the future discounted cash flows of the businesses to
which goodwill relates and have determined that there is no impairment of the
goodwill recorded as of December 31, 2009.
During the fourth quarter of 2008, changes to
the global economic environment resulting in uncertain capital markets and
reductions in global economic activity had severe adverse impacts on stock
markets and oil and natural gas prices, both of which contributed to a
significant decline in our company’s stock price and corresponding market
capitalization. For most of the fourth quarter, our market capitalization was
below the recorded net book value of our balance sheet, including goodwill. The
accounting principles regarding goodwill acknowledge that the observed market
prices of individual trades of a company’s stock (and thus its computed market
capitalization) may not be representative of the fair value of the company as a
whole. Substantial value may arise from the ability to take advantage of
synergies and other benefits that flow from control over another entity.
Consequently, measuring the fair value of a collection of assets and liabilities
that operate together in a controlled entity is different from measuring the
fair value of a single share of that entity’s common stock. Therefore, once the
fair values of the reporting units were determined, we also added a control
premium to the calculations. This control premium is judgmental and is based on
observed mergers and acquisitions in our industry.
After determining the fair values of our
various reporting units which had recorded goodwill as of December 31, 2008, it
was determined that our Production Testing and Compressco reporting units passed
the first step of the goodwill impairment test, while our Fluids and Offshore
Services reporting units did not pass the first step. Maritech does not have any
recorded goodwill. As described above, the second step of the goodwill
impairment test uses the estimated fair value for the Fluids and Offshore
Services reporting units as the purchase price in a hypothetical acquisition of
the reporting unit. The allocation of this purchase price includes hypothetical
adjustments to the carrying values of several asset carrying values for the
Fluids and Offshore Services reporting units. After making these purchase price
allocation adjustments, there was no residual purchase price to be allocated to
goodwill. Based on this analysis, we concluded that an impairment of the entire
amount of recorded goodwill for our Fluids and Offshore Services reporting units
was required, resulting in a charge to earnings of $47.1 million during the
fourth quarter of 2008.
The changes in the
carrying amount of goodwill by reporting unit for the two year period ended
December 31, 2009, are as follows:
|
Fluids
|
Offshore
Services
|
Maritech
|
Production
Testing
|
Compressco
|
Total
|
|||||||||||||||||||
|
(In
Thousands)
|
||||||||||||||||||||||||
|
Balance as of
December 31, 2007
|
$ | 24,641 | $ | 23,223 | $ | - | $ | 10,364 | $ | 72,107 | $ | 130,335 | ||||||||||||
|
Goodwill
adjustments
|
- | - | - | - | 54 | 54 | ||||||||||||||||||
|
Foreign
currency fluctuations
|
(791 | ) | - | - | - | - | (791 | ) | ||||||||||||||||
|
Goodwill
impairments
|
(23,850 | ) | (23,223 | ) | - | - | - | (47,073 | ) | |||||||||||||||
|
Balance as of
December 31, 2008
|
- | - | - | 10,364 | 72,161 | 82,525 | ||||||||||||||||||
|
Goodwill
adjustments
|
- | 3,809 | - | 12,671 | - | 16,480 | ||||||||||||||||||
|
Balance as of
December 31, 2009
|
$ | - | $ | 3,809 | $ | - | $ | 23,035 | $ | 72,161 | $ | 99,005 | ||||||||||||
F-11
In
March 2006, we acquired Beacon Resources, LLC (Beacon), a production testing
operation, for approximately $15.6 million paid at closing. In addition, the
acquisition agreement provided for additional contingent consideration of up to
$19.1 million, depending on the average of Beacon’s annual pretax results of
operations over the three year period following the closing date through March
2009. Based on Beacon’s annual pretax results of operations during this three
year period, we paid $12.7 million in April 2009 to the sellers pursuant to this
contingent consideration provision. This amount was charged to goodwill
associated with the acquisition of Beacon.
In
March 2006, we acquired the assets and operations of Epic Divers, Inc. and
certain affiliated companies (Epic), a full service commercial diving operation.
In June 2006, Epic purchased a dynamically positioned dive support vessel and
saturation diving unit. Pursuant to the Epic Asset Purchase Agreement, a portion
of the net profits earned by this dive support vessel and saturation diving unit
over the initial three year term following its purchase was to be paid to the
sellers. Based on the vessel’s high utilization following the 2008 hurricanes,
we paid $3.8 million in July 2009 pursuant to this contingent consideration
provision. This amount was charged to goodwill associated with the acquisition
of Epic.
Impairment
of Long-Lived Assets
Impairments of long-lived assets are determined
periodically when indicators of impairment are present. If such indicators are
present, the determination of the amount of impairment is based on our judgments
as to the future undiscounted operating cash flows to be generated from these
assets throughout their estimated useful lives. If these undiscounted cash flows
are less than the carrying amount of the related asset, an impairment is
recognized for the excess of the carrying value over its fair value. The
assessment of oil and gas properties for impairment is based on the risk
adjusted future estimated cash flows from our proved, probable, and possible
reserves. Assets held for disposal are recorded at the lower of carrying value
or estimated fair value less estimated selling costs.
During 2009, 2008,
and 2007, we identified impairments totaling approximately $11.4 million, $42.7
million, and $71.8 million, respectively, net of intercompany eliminations, of
the net carrying value of certain Maritech oil and gas properties. The
impairments during 2009 were primarily due to decreased production volumes or an
increase in the associated decommissioning liability. The impairments during
2008 were primarily due to the impact of lower oil and natural gas pricing. In
addition, certain properties were impaired as a result of decreased production
volumes and increases in the associated decommissioning liabilities,
particularly as a result of the 2008 hurricanes. The impairments during 2007
were caused primarily due to the reversal of anticipated insurance recoveries
resulting in increased decommissioning liabilities due to certain future well
intervention and debris removal costs being contested by our insurance provider.
Impairments were also recorded during 2007 on certain other properties as a
result of changes in development plans following Maritech’s acquisition of
certain oil and gas properties in December 2007. In addition, certain properties
were also impaired during 2007 due to decreased production volumes or an
increase in the associated decommissioning liability.
Our Fluids Division owns a 50% interest in an
unconsolidated joint venture whose assets consist primarily of a calcium
chloride plant located in Europe. During 2009, the joint venture partner
announced the planned shutdown of its adjacent plant facility, which supplies
raw material to the calcium chloride plant. As a result, the joint venture’s
calcium chloride plant was also shut down. During 2009, we reduced our
investment in the joint venture to its estimated fair value based on the
estimated plant decommissioning costs and salvage value cash flows of the joint
venture, resulting in an impairment of our investment in the joint venture of
$6.5 million. During 2008, we identified impairments totaling approximately $8.7
million associated with a portion of the net carrying value of certain Offshore
Services assets. Approximately $7.3 million of these impairments was as a result
of decreased expected future cash flows from one of the segment’s barge
vessels.
Decommissioning
Liabilities
Related to our
acquired interests in oil and gas properties, we estimate the third party fair
values (including an estimated profit) to plug and abandon wells, decommission
the pipelines and platforms, and clear the sites, and we use these estimates to
record Maritech’s decommissioning liabilities, net of amounts allocable to joint
interest owners, anticipated insurance recoveries, and any amounts contractually
agreed to be paid in the future by the previous owners of the properties. In
some cases, previous owners of acquired oil and gas properties are contractually
obligated to pay Maritech a fixed amount for the future well abandonment
F-12
and decommissioning
work on these properties as such work is performed. As of December 31, 2009 and
2008, our Maritech subsidiary’s decommissioning liabilities are net of
approximately $43.6 million and $48.7 million, respectively, of such future
reimbursements from these previous owners.
In
estimating the decommissioning liabilities, we perform detailed estimating
procedures, analysis, and engineering studies. Whenever practical and cost
effective, Maritech will utilize the services of its affiliated companies to
perform well abandonment and decommissioning work. When these services are
performed by an affiliated company, all recorded intercompany revenues are
eliminated in the consolidated financial statements. The recorded
decommissioning liability associated with a specific property is fully
extinguished when the property is completely abandoned. The liability is first
reduced by all cash expenses incurred to abandon and decommission the property.
If the liability exceeds (or is less than) our actual out-of-pocket costs, the
difference is reported as income (or loss) in the period in which the work is
performed. We review the adequacy of our decommissioning liabilities whenever
indicators suggest that the estimated cash flows underlying the liabilities have
changed materially. The timing and amounts of these cash flows are subject to
changes in the energy industry environment and may result in additional
liabilities to be recorded, which, in turn, would increase the carrying values
of the related properties. In connection with 2008 and 2007 oil and gas property
acquisitions, we assumed net decommissioning liabilities having an estimated
fair value of approximately $20.2 million and $24.8 million, respectively. As a
result of decommissioning work performed, we recorded total reductions to the
decommissioning liabilities for the years 2009, 2008, and 2007 of $74.6 million,
$16.5 million, and $32.9 million, respectively. We made adjustments to increase
our decommissioning liabilities during the years 2009, 2008, and 2007 as a
result of changes in the timing or amount of future cash flows of approximately
$47.1 million, $43.1 million, and $63.3 million, respectively. A large portion
of the adjustments for each of these years was due to the increased
decommissioning liabilities associated with certain Maritech offshore platforms
which were destroyed by hurricanes in 2005 and 2008.
Environmental
Liabilities
Environmental
expenditures which result in additions to property and equipment are
capitalized, while other environmental expenditures are expensed. Environmental
remediation liabilities are recorded on an undiscounted basis when environmental
assessments or cleanups are probable and the costs can be reasonably estimated.
Estimates of future environmental remediation expenditures often consist of a
range of possible expenditure amounts, a portion of which may be in excess of
amounts of liabilities recorded. In this instance, we disclose the full range of
amounts reasonably possible of being incurred. Any changes or developments in
environmental remediation efforts are accounted for and disclosed each quarter
as they occur. Any recoveries of environmental remediation costs from other
parties are recorded as assets when their receipt is deemed
probable.
Complexities
involving environmental remediation efforts can cause the estimates of the
associated liability to be imprecise. Factors which cause uncertainties
regarding the estimation of future expenditures include, but are not limited to,
the effectiveness of the anticipated work plans in achieving targeted results
and changes in the desired remediation methods and outcomes as prescribed by
regulatory agencies. Uncertainties associated with environmental remediation
contingencies are pervasive and often result in wide ranges of reasonably
possible outcomes. Estimates developed in the early stages of remediation can
vary significantly. Normally, a finite estimate of cost does not become fixed
and determinable at a specific point in time. Rather, the costs associated with
environmental remediation become estimable as the work is performed and the
range of ultimate cost becomes more defined. It is possible that cash flows and
results of operations could be materially affected by the impact of the ultimate
resolution of these contingencies.
Revenue
Recognition
Revenues are recognized when finished products
are shipped or services have been provided to unaffiliated customers and only
when collectability is reasonably assured. Sales terms for our products are FOB
shipping point, with title transferring at the point of shipment. Revenue is
recognized at the point of transfer of title. We recognize oil and gas product
sales revenues from our Maritech subsidiary’s interests in producing wells as
oil and gas is produced and sold from those wells. Oil and gas sold is not
significantly different from Maritech’s share of production. With regard to
turnkey contracts, revenues are recognized using the percentage-of-completion
method based on the ratio of costs incurred to total estimated costs at
completion. Total project revenue and cost estimates for turnkey 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.
F-13
Oil
and Gas Balancing
As part of our Maritech subsidiary’s
acquisitions of producing properties, we have acquired oil and gas balancing
receivables and payables related to certain properties. We allocate value for
any acquired oil and gas balancing positions using estimated fair value amounts
expected to be received or paid in the future. Amounts related to underproduced
volume positions acquired are reflected as assets and amounts related to
overproduced volume positions acquired are reflected as liabilities. At December
31, 2009 and 2008, we reflected oil and gas balancing receivables of $3.5
million and $3.6 million, respectively, in accounts receivable or other
long-term assets and oil and gas balancing payables of $6.2 million and $6.4
million, respectively, in accrued liabilities or other long-term liabilities. We
recognize oil and gas product sales from our Maritech subsidiary’s interest in
producing wells, based on its entitled share of oil and natural gas produced and
sold from those wells. Changes to our oil and gas balancing receivable or
payable are valued at the lower of the price in effect at time of production,
current market price, or contract price, if applicable.
Operating
Costs
Cost of product
sales includes direct and indirect costs of manufacturing and producing our
products, including raw materials, fuel, utilities, labor, overhead, repairs and
maintenance, materials, services, transportation, warehousing, equipment
rentals, insurance, and taxes. In addition, cost of product sales includes oil
and gas operating expense. Cost of services and rentals includes operating
expenses we incur in delivering our services, including labor, equipment rental,
fuel, repair and maintenance, transportation, overhead, insurance, and certain
taxes. We include in product sales revenues the reimbursements we receive from
customers for shipping and handling costs. Shipping and handling costs are
included in cost of product sales. Amounts we incur for “out-of-pocket” expenses
in the delivery of our services are recorded as cost of services and rentals.
Reimbursements for “out-of-pocket” expenses we incur in the delivery of our
services are recorded as service revenues. Depreciation, depletion,
amortization, and accretion includes depreciation expense for all of our
facilities, equipment and vehicles, depletion and dry hole expense on our oil
and gas properties, amortization expense on our intangible assets, and accretion
expense related to our decommissioning and other asset retirement
obligations.
We
include in general and administrative expense all costs not identifiable to our
specific product or service operations, including divisional and general
corporate overhead, professional services, corporate office costs, sales and
marketing expenses, insurance, and taxes.
Repair
Costs and Insurance Recoveries
During 2009, one of
our Fluids Division’s transport barges capsized and sank while docked near our
West Memphis, Arkansas, manufacturing facility, destroying the vessel and the
majority of the inventory cargo. The damages associated with the sunken
transport barge consist of the cost of recovery efforts, replacement or repair
of the barge, and the lost inventory cargo. Total damages associated with the
sunken barge were approximately $4.6 million, substantially all of which are
expected to be reimbursed from insurance.
During 2008, we
incurred significant damage to certain of our onshore and offshore operating
equipment and facilities, primarily as a result of Hurricane Ike. Our Maritech
subsidiary suffered varying levels of damage to the majority of its offshore oil
and gas producing platforms, and three of its offshore platforms and one of its
inland water production facilities were destroyed. During 2005, as a result of
Hurricanes Katrina and Rita, our Maritech subsidiary also suffered damage to the
majority of its offshore oil and gas producing platforms, and three of its
platforms and one of its inland water production facilities were also
destroyed.
Hurricane damage
repair efforts consist of the repair of damaged facilities and equipment, the
well intervention, abandonment, decommissioning, and debris removal associated
with the destroyed offshore platforms, and the construction of replacement
platforms and facilities, and the redrilling of destroyed wells. The
reconstruction of the two inland water production facilities has been
substantially completed, and one of the platforms destroyed in 2008 was
decommissioned during 2009. In addition, a majority of our damaged facilities
and equipment, including our offshore platforms that were only partially
damaged, have been repaired. Damage assessment costs and repair expenses up to
the amount of insurance deductibles or not covered by insurance are charged to
earnings as they are incurred. We recognized hurricane related repair expenses
for each of the years ended December 31, 2009, 2008, and 2007 of $8.2 million,
$8.5 million, and $13.5 million, respectively.
F-14
The estimated
amount of future well intervention, abandonment, decommissioning, and debris
removal costs were initially recorded in the period in which such damage
occurred, net of expected insurance recoveries, as part of Maritech’s
decommissioning liabilities. See further discussion of Maritech’s
decommissioning liabilities in
Decommissioning Liabilities
section above. Through December 31, 2009, we have expended approximately $75.8
million for the well intervention, abandonment, decommissioning, and debris
removal work performed on the destroyed platforms and production facilities. For
certain of the destroyed platforms, however, a significant amount of such work
remains to be completed. The majority of the well intervention efforts to date
have been performed by our Offshore Services segment. We estimate that future
well intervention, abandonment, decommissioning, debris removal, platform
reconstruction, and well redrill efforts associated with the destroyed platforms
will cost approximately $95 to $110 million net to our interest before any
insurance recoveries. Approximately $50 to $60 million of this cost relates to
platforms destroyed by Hurricane Ike, and we anticipate that the majority of
these costs will be reimbursed by insurance.
One of the offshore
platforms destroyed in 2008 by Hurricane Ike served a key producing field. We
are currently planning to construct a new platform from which we can redrill
certain of the wells associated with the destroyed platform in order to restore
a portion of the production from this field. We estimate that the cost to
construct the platform and redrill these wells will be approximately $25 to $30
million, net to our interest and before insurance recoveries, and will be
capitalized as oil and gas properties, net of any insurance
recoveries.
In the past,
we have maintained insurance protection which we believe to be customary and in
amounts sufficient to reimburse us for a majority of the repair, well
intervention, abandonment, decommissioning, and debris removal costs associated
with the damages incurred from hurricanes and other damages, such as the value
of the lost inventory and the cost to replace the sunken transport barge,
reconstruct the destroyed platforms and facilities, and redrill the associated
wells. Such insurance coverage is subject to certain coverage limits. For our
Maritech hurricane damages caused by Hurricane Ike, we anticipate that we will
exceed these coverage limits. In addition, with regard to the 2008 hurricanes,
the relevant insurance policies provide for deductibles of up to $5 million per
hurricane, and this deductible has been satisfied for Hurricane Ike. No
significant additional insurance recoveries will be received related to the 2005
hurricanes. Due to the prohibitively high premium cost and deductible, and the
significantly reduced policy limit and confining sub-limits for renewal of
Maritech’s windstorm insurance coverage that terminated on May 31, 2009,
beginning June 2009, we have elected to self-insure Maritech’s windstorm damage
risk for the current coverage period ending May 2010. We have, however, renewed
Maritech’s operational risk policies.
With regard to the
costs incurred which we believe will qualify for coverage under our various
insurance policies, we recognize anticipated insurance recoveries when
collection is deemed probable. Any recognition of anticipated insurance
recoveries is used to offset the original charge to which the insurance relates.
The amount of anticipated insurance recoveries is included either in accounts
receivable or as a reduction of Maritech’s decommissioning liabilities in the
accompanying consolidated balance sheets.
The changes in
anticipated insurance recoveries, including anticipated recoveries associated
with the sunken barge and other non-hurricane related claims, during the most
recent two year period are as follows:
|
Year
Ended December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(In
Thousands)
|
||||||||
|
Beginning
balance
|
$ | 33,591 | $ | 11,279 | ||||
|
Activity in
the period:
|
||||||||
|
Damage
related expenditures
|
21,228 | 31,952 | ||||||
|
Insurance
reimbursements
|
(27,176 | ) | (9,303 | ) | ||||
|
Contested
insurance recoveries
|
(651 | ) | (337 | ) | ||||
|
Ending
balance at December 31
|
$ | 26,992 | $ | 33,591 | ||||
As
discussed further in Note J – Commitments and Contingencies,
Insurance Litigation,
Maritech incurred certain well intervention, debris removal, and repair costs
related to damage from Hurricanes Katrina and Rita which were not reimbursed by
its insurers. In December 2007, Maritech filed a lawsuit against its
F-15
insurers and other
associated parties in an attempt to collect pursuant to the applicable policies.
Accordingly, during the fourth quarter of 2007, we reversed $62.9 million of
anticipated insurance recoveries as they were deemed to be not probable of
collection. This reversal resulted in a charge to earnings of approximately
$60.1 million during 2007. A significant portion of the amounts capitalized to
oil and gas properties following the increase in decommissioning liabilities due
to hurricanes resulted in increased oil and gas property impairments during 2008
and 2007. See further discussion in
Impairment of Long-Lived Assets
section above. During the fourth quarter of 2009, Maritech entered into a
settlement agreement under which it received approximately $40.0 million of the
previously unreimbursed costs. We have reviewed the types of estimated well
intervention costs incurred or to be incurred related to Hurricane Ike. Despite
our belief that substantially all of these costs in excess of deductibles and
within policy limits will qualify for coverage under our insurance policies, any
costs that are similar to the costs that were not initially reimbursed following
Hurricanes Katrina and Rita have been excluded from anticipated insurance
recoveries and were either capitalized to the associated oil and gas properties
or expensed.
Approximately $70
to $80 million of the $95 to $110 million remaining hurricane related costs
associated with the destroyed platforms is for the well intervention,
abandonment, decommissioning, and debris removal. An estimate of the cost of
this work has been accrued for as part of Maritech’s decommissioning liability,
net of anticipated insurance recoveries. Anticipated insurance recoveries that
have been reflected as a reduction of our decommissioning liabilities were $10.3
million at December 31, 2009, and $19.5 million at December 31, 2008.
Anticipated insurance recoveries that have been reflected as insurance
receivables, including the damages incurred during 2009 from the sunken barge,
were $16.7 million at December 31, 2009, and $14.1 million at December 31, 2008.
Subsequent to December 31, 2009, and through February 26, 2010, we have
collected an additional $10.8 million of insurance recoveries. Uninsured assets
that were destroyed during the storms are charged to earnings. Repair costs
incurred, and the net book value of any destroyed assets which are covered under
our insurance policies, are anticipated insurance recoveries which are included
in accounts receivable. Repair costs not considered probable of collection are
charged to earnings. Insurance recoveries in excess of destroyed asset carrying
values and repair costs incurred are credited to earnings when received. During
2009, 2008, and 2007, approximately $5.4 million, $0.7 million, and $3.2
million, respectively, of such excess proceeds were credited to earnings.
Intercompany profit on repair work performed by our Offshore Services segment is
not recognized until such time as insurance claim proceeds are
received.
Income
Taxes
Deferred tax assets and liabilities are
recognized for the future tax consequences attributable to differences between
the financial statement carrying amounts of existing assets and liabilities and
their respective tax basis amounts. Deferred tax assets and liabilities are
measured using enacted tax rates expected to apply to taxable income in the
years in which those temporary differences are expected to be recovered or
settled. The effect of a change in tax rates is recognized as income or expense
in the period that includes the enactment date.
Income
(Loss) per Common Share
The calculation of basic earnings per share
excludes any dilutive effects of options. The calculation of diluted earnings
per share includes the dilutive effect of stock options, which is computed using
the treasury stock method during the periods such options were outstanding. A
reconciliation of the common shares used in the computations of income (loss)
per common and common equivalent shares is presented in Note P – Income (Loss)
Per Share.
Foreign
Currency Translation
We have designated the euro, the British pound,
the Norwegian krone, the Canadian dollar, the Mexican peso, and the Brazilian
real as the functional currency for our operations in Finland and Sweden, the
United Kingdom, Norway, Canada, Mexico, and Brazil, respectively. The U.S.
dollar is the designated functional currency for all of our other foreign
operations. The cumulative translation effects of translating the accounts from
the functional currencies into the U.S. dollar at current exchange rates are
included as a separate component of stockholders' equity.
F-16
Fair
Value Measurements
Effective January 1, 2008, we adopted the
provisions of the Financial Accounting Standards Board Accounting Standards
Codification (FASB Codification) Topic 820, “Fair Value Measurements and
Disclosures,” which defines fair value, establishes a framework for measuring
fair value, and expands disclosures about fair value measurements. FASB
Codification Topic 820 establishes a fair value hierarchy and requires
disclosure of fair value measurements within that hierarchy.
Fair value is
defined as “the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market participants at
the measurement date” within an entity’s principal market, if any. The principal
market is the market in which the reporting entity would sell the asset or
transfer the liability with the greatest volume and level of activity,
regardless of whether it is the market in which the entity will ultimately
transact for a particular asset or liability or if a different market is
potentially more advantageous. Accordingly, this exit price concept may result
in a fair value that may differ from the transaction price or market price of
the asset or liability.
The fair value hierarchy prioritizes inputs to
valuation techniques used to measure fair value. Fair value measurements should
maximize the use of observable inputs and minimize the use of unobservable
inputs, where possible. Observable inputs are developed based on market data
obtained from sources independent of the reporting entity. Unobservable inputs
may be needed to measure fair value in situations where there is little or no
market activity for the asset or liability at the measurement date and are
developed based on the best information available in the circumstances, which
could include the reporting entity’s own judgments about the assumptions market
participants would utilize in pricing the asset or liability.
We utilize fair value measurements to account
for certain items and account balances within our consolidated financial
statements. Fair value measurements are utilized in the allocation of purchase
consideration for acquisition transactions to the assets and liabilities
acquired, including intangible assets and goodwill. In addition, we utilize fair
value measurements in the initial recording of our decommissioning and other
asset retirement obligations. Fair value measurements may also be utilized on a
nonrecurring basis, such as for the impairment of long-lived assets, including
goodwill. The fair value of our financial instruments, which may include cash,
temporary investments, accounts receivable, short-term borrowings, and long-term
debt pursuant to our bank credit agreement, approximate their carrying amounts.
The fair value of our long-term Senior Notes at December 31, 2009 was
approximately $323.6 million compared to a carrying amount of approximately
$310.1 million as current rates are more favorable than actual Senior Note
interest rates. We calculate the fair value of our Senior Notes internally,
using current market conditions and average cost of debt. We have not calculated
or disclosed recurring fair value measurements of non-financial assets and
non-financial liabilities.
We also utilize fair value measurements on a
recurring basis in the accounting for our derivative contracts used to hedge a
portion of our oil and natural gas production cash flows. For these fair value
measurements, we compare forward oil and natural gas pricing data from published
sources over the remaining derivative contract term to the contract swap price
and calculate a fair value using market discount rates. A summary of these fair
value measurements as of December 31, 2009 and 2008 is as follows:
|
Fair
Value Measurements as of December 31, 2009 Using
|
||||||||||||||||
|
Quoted
Prices in
|
||||||||||||||||
|
Active
Markets for
|
Significant
Other
|
Significant
|
||||||||||||||
|
Identical
Assets
|
Observable
|
Unobservable
|
||||||||||||||
|
Total
as of
|
or
Liabilities
|
Inputs
|
Inputs
|
|||||||||||||
|
Description
|
December
31, 2009
|
(Level
1)
|
(Level
2)
|
(Level
3)
|
||||||||||||
|
(In
Thousands)
|
||||||||||||||||
|
Asset for
natural gas
|
||||||||||||||||
|
swap
contracts
|
$ | 19,926 | $ | - | $ | 19,926 | $ | - | ||||||||
|
Liability for
oil swap contracts
|
(2,618 | ) | - | (2,618 | ) | - | ||||||||||
|
Total
|
$ | 17,308 | ||||||||||||||
F-17
|
Fair
Value Measurements as of December 31, 2008 Using
|
||||||||||||||||
|
Quoted
Prices in
|
||||||||||||||||
|
Active
Markets for
|
Significant
Other
|
Significant
|
||||||||||||||
|
Identical
Assets
|
Observable
|
Unobservable
|
||||||||||||||
|
Total
as of
|
or
Liabilities
|
Inputs
|
Inputs
|
|||||||||||||
|
Description
|
December
31, 2008
|
(Level
1)
|
(Level
2)
|
(Level
3)
|
||||||||||||
|
(In
Thousands)
|
||||||||||||||||
|
Asset for
natural gas
|
||||||||||||||||
|
swap
contracts
|
$ | 35,659 | $ | - | $ | 35,659 | $ | - | ||||||||
|
Asset for oil
swap contracts
|
41,491 | - | 41,491 | - | ||||||||||||
|
Total
|
$ | 77,150 | ||||||||||||||
During 2009,
certain Maritech oil and gas property impairments of $11.4 million were charged
to earnings. For a portion of these impaired properties, the change in the fair
value of the properties was due to decreased expected future cash flows based on
forward oil and natural gas pricing data from published sources. Because such
published forward pricing data was applied to estimated oil and gas reserve
volumes based on our internally prepared reserve estimates, such fair value
calculation is based on significant unobservable inputs (Level 3) in accordance
with the fair value hierarchy.
Our Fluids Division
owns a 50% interest in an unconsolidated joint venture whose assets consist
primarily of a calcium chloride plant located in Europe. During 2009, the joint
venture partner announced the shutdown of its adjacent plant facility, which
supplies raw material to the calcium chloride plant. As a result, the joint
venture’s calcium chloride plant was also shut down. During the second quarter
2009, we reduced our investment in the joint venture to its estimated fair value
based on the estimated plant decommissioning costs and salvage value cash flows
of the joint venture, resulting in an impairment of our investment in the joint
venture of $6.5 million. Because the investment fair value was determined based
on internally prepared estimates, such fair value calculation is based on
significant unobservable inputs (Level 3) in accordance with the fair value
hierarchy.
A summary of these nonrecurring fair value
measurements as of December 31, 2009, using the fair value hierarchy is as
follows:
|
Fair
Value Measurements as of
|
||||||||||||||||||||
|
December
31, 2009 Using
|
||||||||||||||||||||
|
Quoted
Prices in
|
||||||||||||||||||||
|
Active
Markets for
|
Significant
Other
|
Significant
|
||||||||||||||||||
|
Identical
Assets
|
Observable
|
Unobservable
|
||||||||||||||||||
|
Year
Ended
|
or
Liabilities
|
Inputs
|
Inputs
|
Total
|
||||||||||||||||
|
Description
|
December
31, 2009
|
(Level
1)
|
(Level
2)
|
(Level
3)
|
Losses
|
|||||||||||||||
|
(In
Thousands)
|
||||||||||||||||||||
|
Impairments
of oil and
|
||||||||||||||||||||
|
gas
properties
|
$ | 13,228 | $ | - | $ | - | $ | 13,228 | $ | 11,410 | ||||||||||
|
Impairment of
investment
|
||||||||||||||||||||
|
in
unconsolidated
|
||||||||||||||||||||
|
joint
venture
|
250 | - | - | 250 | 6,540 | |||||||||||||||
|
Other
|
- | - | - | - | 1,581 | |||||||||||||||
|
Total
|
$ | 19,531 | ||||||||||||||||||
New
Accounting Pronouncements
In
June 2009, the FASB published Statement of Financial Accounting Standard (SFAS)
No. 168, “The
FASB Accounting
Standards Codification
and the Hierarchy of Generally Accepted Accounting
Principles – a replacement of FASB Statement No. 162,” which establishes the
FASB Codification as the source of authoritative U.S. generally accepted
accounting principles (GAAP) recognized by the FASB to be applied by
nongovernmental entities. Beginning on the effective date of the standard (now
incorporated into FASB Codification Subtopic 105-10), the FASB Codification
superseded all then-existing non-SEC accounting and reporting standards. All
other non-grandfathered non-SEC accounting literature not included in the FASB
Codification has become non-authoritative. The standard is effective for
financial statements issued for interim
F-18
and annual periods
ending after September 15, 2009. In the FASB’s view, the issuance of the
standard and the FASB Codification will not change GAAP for public companies,
and, accordingly, the adoption of the standard did not have a significant impact
on our financial statements.
In
March 2008, the FASB published SFAS No. 161, “Disclosures about Derivative
Instruments and Hedging Activities, an amendment of FASB Statement No. 133,”
(FASB Codification Topic 815, “Derivatives and Hedging”), which requires
entities to provide greater transparency about (1) how and why an entity uses
derivative instruments, (2) how derivative instruments and related hedged items
are accounted for under FASB Codification Topic 815 (SFAS No. 133 and its
related interpretations); and (3) how derivative instruments and related hedged
items affect an entity’s financial position, results of operations, and cash
flows. This standard is effective for financial statements issued for fiscal
years and interim periods within those fiscal years, beginning after November
15, 2008. Accordingly, we adopted the new disclosure requirements as of January
1, 2009.
In
December 2007, the FASB published SFAS No. 141R, “Business Combinations,”
(incorporated into FASB Codification Topic 805, “Business Combinations”), which
established principles and requirements for how an acquirer of a business (1)
recognizes and measures in its financial statements the identifiable assets
acquired, the liabilities assumed, and any noncontrolling interest in the
acquiree; (2) recognizes and measures the goodwill acquired in the business
combination or a gain from a bargain purchase; and (3) determines what
information to disclose to enable users of the financial statements to evaluate
the nature and financial effects of the business combination. The standard
changes many aspects of the accounting for business combinations and applies
prospectively to business combinations for which the acquisition date is on or
after the beginning of the first annual reporting period beginning on or after
December 15, 2008. We adopted this standard as of January 1, 2009 with no
significant impact, as there have been no acquisitions during 2009. However, the
standard is expected to significantly impact how we account for and disclose
future acquisition transactions.
In
May 2009, the FASB published SFAS No. 165, “Subsequent Events,” (FASB
Codification Topic 855, “Subsequent Events”), which establishes general
standards of accounting for and disclosure of events that occur after the
balance sheet date but before financial statements are issued or are available
to be issued. In particular, it sets forth (1) the period after the balance
sheet date during which management of a reporting entity should evaluate events
or transactions that may occur for potential recognition or disclosure; (2) the
circumstances under which an entity should recognize events or transactions
occurring after the balance sheet date; and (3) the disclosures that an entity
should make about events or transactions that occurred after the balance sheet
date. This standard is effective for financial statements for periods ending
after June 15, 2009. We adopted this standard as of July 1, 2009, however the
standard did not have a significant impact on our financial
statements.
In
December 2008, the SEC released its “Modernization of Oil and Gas Reporting”
rules, which revise the disclosure of oil and gas reserve information. The new
disclosure requirements include provisions that permit the use of new
technologies to determine proved reserves in certain circumstances. The new
requirements also will allow companies to disclose their probable and possible
reserves and require companies to (1) report on the independence and
qualifications of a reserves preparer or auditor; (2) file reports when a third
party is relied upon to prepare reserve estimates or conduct a reserves audit;
and (3) report oil and gas reserves using an average price based upon the prior
twelve month period, rather than year-end prices. These new reporting
requirements are effective for annual reports on Form 10-K for fiscal years
ending on or after December 31, 2009. We adopted these new SEC oil and gas
reserve rules as of December 31, 2009, however, they did not have a significant
impact on our financial statements.
NOTE
C — DISCONTINUED OPERATIONS
During the fourth quarter of 2007, we disposed
of our process services operations through a sale of the associated assets and
operations for total cash proceeds of approximately $58.9 million. Our process
services operation provided the technology and services required for the
separation and recycling of oily residuals generated from petroleum refining
operations. As a result of this disposal, we reflected a gain on the sale of our
process services business of approximately $25.8 million, net of tax, for the
difference between the sales proceeds and the net carrying value of the disposed
net assets. The calculation of this gain included $2.7 million of goodwill
related to the process services operation. Our process services operation was
previously included as a component of our Production Enhancement
Division.
F-19
A
summary of financial information related to our discontinued operations for each
of the past three years is as follows:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(In
Thousands)
|
||||||||||||
|
Revenues
|
||||||||||||
|
Process
services operations
|
$ | - | $ | - | $ | 16,145 | ||||||
|
Venezuelan
fluids and production testing operations
|
- | - | 608 | |||||||||
| $ | - | $ | - | $ | 16,753 | |||||||
|
Income (loss), net of taxes
|
||||||||||||
|
Process
services operations, net of taxes of $(86),
|
||||||||||||
|
$(226),
and $1,182, respectively
|
$ | (161 | ) | $ | (424 | ) | $ | 1,939 | ||||
|
Venezuelan
fluids and production testing operations,
|
||||||||||||
|
net
of taxes of $101, $1, and $90, respectively
|
(216 | ) | (1,501 | ) | (137 | ) | ||||||
|
Other
discontinued operations
|
(49 | ) | (556 | ) | (79 | ) | ||||||
| $ | (426 | ) | $ | (2,481 | ) | $ | 1,723 | |||||
|
Gain from disposal
|
||||||||||||
|
Process
services operation, net of taxes of $228, $0 and
|
||||||||||||
|
$14,906,
respectively
|
$ | 423 | $ | - | $ | 25,827 | ||||||
|
Total income (loss) from discontinued operations,
net of tax
|
||||||||||||
|
Process
services
|
$ | 262 | $ | (424 | ) | $ | 27,766 | |||||
|
Venezuelan
fluids and production testing operations
|
(216 | ) | (1,501 | ) | (137 | ) | ||||||
|
Other
discontinued operations
|
(49 | ) | (556 | ) | (79 | ) | ||||||
| $ | (3 | ) | $ | (2,481 | ) | $ | 27,550 | |||||
NOTE
D — ACQUISITIONS AND DISPOSITIONS
During 2009, our
Maritech subsidiary sold interests in certain oil and gas properties in two
separate transactions. As a result of these transactions, the buyers of the
properties assumed an aggregate of approximately $6.3 million of Maritech’s
associated decommissioning liabilities. Maritech received cash of approximately
$4.2 million as a result of these sale transactions and recognized gains
totaling approximately $7.3 million. The amount of oil and gas reserve volumes
associated with the sold properties was immaterial.
In
January 2008, our Maritech subsidiary acquired oil and gas producing properties
located in the offshore Gulf of Mexico from Stone Energy Corporation in exchange
for the assumption of the associated decommissioning liabilities with a fair
value of approximately $19.9 million. In addition, we paid $13.7 million of
cash, $2.3 million of which had been paid on deposit in November 2007. The
acquired properties were recorded at their cost of approximately $33.6
million.
During the third
quarter of 2008, Maritech sold certain oil and gas properties and assets in
which the buyers assumed an aggregate of approximately $4.7 million of
Maritech’s associated decommissioning liabilities. Maritech retained a
decommissioning obligation of approximately $0.2 million in these transactions
and recognized gains totaling approximately $4.5 million. The amount of oil and
gas reserve volumes associated with the sold properties was
immaterial.
In
April 2007, we acquired certain assets and the operations of a company that
provides fluids transfer and related services in support of high pressure
fracturing processes. The acquisition expanded our Fluids Division’s fluids
transfer and related services business by providing such services to customers
in the Arkansas, TexOma, and ArkLaTex regions. As consideration for the acquired
assets, we paid approximately $8.5 million of cash at closing. We allocated the
purchase price of this acquisition to the fair value of the assets and
liabilities acquired, which consisted of approximately $0.2 million of
inventory, $5.5 million of property, plant, and equipment; $1.4 million of
certain intangible assets; and $1.3 million of goodwill. Intangible assets,
other than goodwill, are amortized over their useful lives, ranging from five to
six years.
In
September 2007, we acquired the assets and operations of E.O.T. Rentals, LLC
(EOT), a business which provides onshore and offshore cutting services and
equipment rentals and services in the U.S. Gulf Coast region. As consideration
for the acquired assets, we paid approximately $6.1 million of cash at closing,
subject to adjustment, with an additional $1.0 million which was paid at
prescribed dates over the subsequent
F-20
two years. We
allocated the purchase price of this acquisition to the fair value of the assets
and liabilities acquired, which consisted of approximately $0.7 million of net
working capital, approximately $2.8 million of property, plant, and equipment;
$0.9 million of certain intangible assets; and $2.5 million of goodwill.
Intangible assets, other than goodwill, are amortized over their useful lives,
ranging from five to six years.
During 2007, our Maritech subsidiary entered
into seven separate transactions in which it sold interests in certain oil and
gas properties and assets. As a result of these transactions, the buyers of
these properties assumed an aggregate of approximately $4.0 million of
Maritech’s associated decommissioning liabilities. Maritech paid total net cash
of approximately $0.5 million in these transactions and recognized gains
totaling approximately $2.4 million. The amount of oil and gas reserve volumes
associated with the sold properties was immaterial.
In
December 2007, our Maritech subsidiary acquired interests in oil and gas
properties located in the offshore Gulf of Mexico from a subsidiary of Cimarex
Energy Company (the Cimarex Properties) in exchange for cash of $59.2 million
after final closing adjustments during 2008 and the assumption of the associated
decommissioning liabilities with a fair value of approximately $23.6 million.
Also in December 2007, an additional interest in one of the Cimarex Properties
was separately acquired from an unrelated third party in exchange for cash of
$2.0 million. The acquired oil and gas properties were recorded at a cost of
approximately $84.8 million.
All of our acquisitions have been accounted for
as purchases, with operations of the companies and businesses acquired included
in the accompanying consolidated financial statements from their respective
dates of acquisition. The purchase price has been allocated to the acquired
assets and liabilities based on a determination of their respective fair values.
The excess of the purchase price over the fair value of the net assets acquired
is included in goodwill and assessed for impairment whenever indicators are
present. We have not recorded any goodwill in conjunction with our oil and gas
property acquisitions.
NOTE
E — LEASES
We lease some of our transportation equipment,
office space, warehouse space, operating locations, and machinery and equipment.
Certain facility storage tanks being constructed are leased pursuant to a ten
year term, which is classified as a capital lease. The office, warehouse, and
operating location leases, which vary from one to ten year terms that expire at
various dates through 2017 and are renewable for three and five year periods on
similar terms, are classified as operating leases. Transportation equipment
leases expire at various dates through 2014 and are also classified as operating
leases. The office, warehouse, and operating location leases, and machinery and
equipment leases generally require us to pay all maintenance and insurance
costs.
Future minimum
lease payments by year and in the aggregate, under non-cancelable capital and
operating leases with terms of one year or more, consist of the following at
December 31, 2009:
|
Capital
Lease
|
Operating
Leases
|
|||||||
|
(In
Thousands)
|
||||||||
|
2010
|
$ | 62 | $ | 4,676 | ||||
|
2011
|
62 | 2,391 | ||||||
|
2012
|
62 | 1,791 | ||||||
|
2013
|
62 | 1,061 | ||||||
|
2014
|
62 | 746 | ||||||
|
After
2014
|
310 | 85 | ||||||
|
Total minimum
lease payments
|
$ | 620 | $ | 10,750 | ||||
Rental expense for all operating leases was
$10.0 million, $13.3 million, and $12.8 million in 2009, 2008, and 2007,
respectively.
F-21
NOTE
F — INCOME TAXES
The income tax
provision attributable to continuing operations for the years ended December 31,
2009, 2008, and 2007 consists of the following:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(In
Thousands)
|
||||||||||||
|
Current
|
||||||||||||
|
Federal
|
$ | 7,762 | $ | (4,840 | ) | $ | (2,319 | ) | ||||
|
State
|
(856 | ) | 5,156 | (1,255 | ) | |||||||
|
Foreign
|
8,453 | 6,491 | 3,841 | |||||||||
| 15,359 | 6,807 | 267 | ||||||||||
|
Deferred
|
||||||||||||
|
Federal
|
18,889 | 794 | 1,325 | |||||||||
|
State
|
1,742 | (1,204 | ) | 1,257 | ||||||||
|
Foreign
|
573 | (657 | ) | (1,908 | ) | |||||||
| 21,204 | (1,067 | ) | 674 | |||||||||
|
Total
tax provision
|
$ | 36,563 | $ | 5,740 | $ | 941 | ||||||
A reconciliation of the provision for income
taxes attributable to continuing operations, computed by applying the federal
statutory rate for the years ended December 31, 2009, 2008, and 2007 to income
before income taxes and the reported income taxes, is as follows:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(In
Thousands)
|
||||||||||||
|
Income tax
provision (benefit) computed at
|
||||||||||||
|
statutory
federal income tax rates
|
$ | 36,880 | $ | (1,370 | ) | $ | 757 | |||||
|
State income
taxes (net of federal benefit)
|
576 | 2,568 | (84 | ) | ||||||||
|
Nondeductible
expenses
|
1,566 | 4,281 | 1,320 | |||||||||
|
Impact of
international operations
|
(1,138 | ) | 1,248 | (1,045 | ) | |||||||
|
Excess
depletion
|
(124 | ) | (239 | ) | (279 | ) | ||||||
|
Tax
credits
|
(237 | ) | (538 | ) | (171 | ) | ||||||
|
Other
|
(960 | ) | (210 | ) | 443 | |||||||
|
Total tax
provision
|
$ | 36,563 | $ | 5,740 | $ | 941 | ||||||
The provision for income taxes includes amounts
related to the anticipated repatriation of certain earnings of our non-U.S.
subsidiaries. Undistributed earnings above the amounts upon which taxes have
been provided, which approximated $5.9 million at December 31, 2009, are
intended to be permanently invested. It is not practicable to determine the
amount of applicable taxes that would be incurred if any such earnings were
repatriated.
Income (loss)
before taxes and discontinued operations includes the following
components:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(In
Thousands)
|
||||||||||||
|
Domestic
|
$ | 82,251 | $ | (11,054 | ) | $ | (8,432 | ) | ||||
|
International
|
23,119 | 7,139 | 10,594 | |||||||||
|
Total
|
$ | 105,370 | $ | (3,915 | ) | $ | 2,162 | |||||
We file U.S. federal, state, and foreign income
tax returns. We believe we have justification for the tax positions utilized in
the various tax returns we file. With few exceptions, we are no longer subject
to U.S. federal, state, local, or non-U.S. income tax examinations by tax
authorities for years prior to 2003.
F-22
We
adopted the provisions of FASB Interpretation No. 48, “Accounting for
Uncertainty in Income Taxes” (now incorporated into FASB Codification Topic 740,
“Income Taxes”), on January 1, 2007. The standard provides guidance on
measurement and recognition in accounting for income tax uncertainties and
provides related guidance on derecognition, classification, disclosure,
interest, and penalties. As a result of the implementation of the standard, we
recognized an approximate $0.1 million increase in the liability for
unrecognized tax benefits, which was accounted for as a reduction to the January
1, 2007 balance of retained earnings.
A
reconciliation of the beginning and ending amount of our gross unrecognized tax
benefit liability is as follows:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(In
Thousands)
|
||||||||||||
|
Gross
unrecognized tax benefits at beginning of period
|
$ | 2,235 | $ | 2,566 | $ | 2,483 | ||||||
|
Increases
in tax positions for prior years
|
561 | - | - | |||||||||
|
Decreases
in tax positions for prior years
|
- | - | - | |||||||||
|
Increases
in tax positions for current year
|
- | 341 | 394 | |||||||||
|
Settlements
|
- | - | - | |||||||||
|
Lapse
in statute of limitations
|
(540 | ) | (672 | ) | (311 | ) | ||||||
|
Gross
unrecognized tax benefits at end of period
|
$ | 2,256 | $ | 2,235 | $ | 2,566 | ||||||
We
recognize interest and penalties related to uncertain tax positions in income
tax expense. During the years ended December 31, 2009, 2008, and 2007, we
recognized approximately $0.5 million, $0.3 million, and $0.6 million,
respectively, in interest and penalties in provision for income tax. As of
December 31, 2009 and 2008, we had approximately $2.0 million and $2.5 million,
respectively, of accrued potential interest and penalties associated with these
uncertain tax positions. The total amount of unrecognized tax benefits that
would affect our effective tax rate if recognized is $1.7 million and $2.2
million as of December 31, 2009 and 2008, respectively. We do not expect a
significant change to the unrecognized tax benefits during the next twelve
months.
We
file tax returns in the U.S. and in various state, local and non-U.S.
jurisdictions. The following table summarizes the earliest tax years that remain
subject to examination by taxing authorities in any major jurisdiction in which
we operate:
|
Jurisdiction
|
Earliest Open Tax Period
|
|
United States
– Federal
|
2006
|
|
United States
– State and Local
|
2002
|
|
Non-U.S.
jurisdictions
|
2003
|
We
use the liability method for reporting income taxes, under which current and
deferred tax assets and liabilities are recorded in accordance with enacted tax
laws and rates. Under this method, at the end of each period, the amounts of
deferred tax assets and liabilities are determined using the tax rate expected
to be in effect when the taxes are actually paid or recovered. We will establish
a valuation allowance to reduce the deferred tax assets when it is more likely
than not that some portion or all of the deferred tax assets will not be
realized. While we have considered future taxable income and ongoing tax
planning strategies in assessing the need for the valuation allowance, there can
be no guarantee that we will be able to realize all of our deferred tax assets.
Significant components of our deferred tax assets and liabilities as of December
31, 2009 and 2008 are as follows:
F-23
|
Deferred Tax
Assets:
|
||||||||
|
December
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(In
Thousands)
|
||||||||
|
Accruals
|
$ | 87,088 | $ | 99,357 | ||||
|
Goodwill
|
5,249 | 7,528 | ||||||
|
All
other
|
26,280 | 23,299 | ||||||
|
Total
deferred tax assets
|
118,617 | 130,184 | ||||||
|
Valuation
allowance
|
(4,255 | ) | (3,337 | ) | ||||
|
Net
deferred tax assets
|
$ | 114,362 | $ | 126,847 | ||||
|
Deferred Tax
Liabilities:
|
||||||||
|
December
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(In
Thousands)
|
||||||||
|
Excess book
over tax basis in
|
||||||||
|
property,
plant, and equipment
|
$ | 161,126 | $ | 148,684 | ||||
|
Unrealized
gains on derivatives
|
13,879 | 28,700 | ||||||
|
All
other
|
14,033 | 15,557 | ||||||
|
Total
deferred tax liability
|
189,038 | 192,941 | ||||||
|
Net
deferred tax liability
|
$ | 74,676 | $ | 66,094 | ||||
The change in the
valuation allowance during 2009 primarily relates to an increase of state
operating loss carryforwards. We believe the ability to generate sufficient
taxable income may not allow us to realize all the tax benefits of the deferred
tax assets within the allowable carryforward period. Therefore, an appropriate
valuation allowance has been provided.
At
December 31, 2009, we had approximately $4.9 million of foreign and state net
operating loss carryforwards. In those countries and states in which net
operating losses are subject to an expiration period, our loss carryforwards, if
not utilized, will expire at various dates from 2010 through 2029. At December
31, 2009, we had approximately $2.1 million of foreign tax credits available to
offset future payment of federal income taxes. The foreign tax credits expire in
varying amounts through 2018.
NOTE
G — ACCRUED LIABILITIES
Accrued liabilities
are detailed as follows:
|
December
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(In
Thousands)
|
||||||||
|
Taxes
payable
|
$ | 13,932 | $ | 7,280 | ||||
|
Oil and gas
drilling advances
|
367 | 11,283 | ||||||
|
Compensation
and employee benefits
|
16,525 | 17,280 | ||||||
|
Oil and gas
producing liabilities
|
20,643 | 23,859 | ||||||
|
Unearned
income
|
12,844 | 189 | ||||||
|
Accrued
inventory supply settlement
|
- | 1,747 | ||||||
|
Other accrued
liabilities
|
20,327 | 25,021 | ||||||
| $ | 84,638 | $ | 86,659 | |||||
F-24
NOTE
H — LONG-TERM DEBT AND OTHER BORROWINGS
Long-term debt consists of the
following:
|
December
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(In
Thousands)
|
||||||||
|
Bank
revolving line of credit facility, due 2011
|
$ | - | $ | 97,368 | ||||
|
5.07% Senior
Notes, Series 2004-A, due 2011
|
55,000 | 55,000 | ||||||
|
4.79% Senior
Notes, Series 2004-B, due 2011
|
40,132 | 39,472 | ||||||
|
5.90% Senior
Notes, Series 2006-A, due 2016
|
90,000 | 90,000 | ||||||
|
6.30% Senior
Notes, Series 2008-A, due 2013
|
35,000 | 35,000 | ||||||
|
6.56% Senior
Notes, Series 2008-B, due 2015
|
90,000 | 90,000 | ||||||
|
European
credit facility
|
- | - | ||||||
| 310,132 | 406,840 | |||||||
|
Less current
portion
|
- | - | ||||||
|
Total
long-term debt
|
$ | 310,132 | $ | 406,840 | ||||
Scheduled
maturities for the next five years and thereafter are as
follows:
|
Year
Ending
|
||||
|
December
31,
|
||||
|
(In
Thousands)
|
||||
|
2010
|
$ | - | ||
|
2011
|
95,132 | |||
|
2012
|
- | |||
|
2013
|
35,000 | |||
|
2014
|
- | |||
|
Thereafter
|
180,000 | |||
| $ | 310,132 | |||
Bank
Credit Facilities
Our bank credit
agreement (the Credit Agreement) provides for available borrowing capacity of up
to $300 million and matures June 27, 2011. The facility is unsecured and is
guaranteed by our material U.S. subsidiaries. Borrowings under the Credit
Agreement bear interest at the British Bankers Association LIBOR rate plus 0.50%
to 1.25%, depending on one of our financial ratios. We pay a commitment fee on
unused portions of the facility at a rate from 0.15% to 0.30%, also depending on
this financial ratio. As of December 31, 2009, there was no balance outstanding
under the credit facility.
The Credit
Agreement contains customary covenants and other restrictions, including certain
financial ratio covenants that were modified from the previous credit facility
agreement. Additionally, the Credit Agreement includes cross-default provisions
relating to any of our other indebtedness 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 pursuant to the Credit
Agreement.
We are
in compliance with all covenants and conditions of our Credit Agreement as of
December 31, 2009. Defaults under the Credit Agreement that are 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
also have a bank line of credit agreement covering the day to day working
capital needs of certain of our European operations (the European Credit
Agreement). The European Credit Agreement provides for available borrowing
capacity of up to 5 million euros (approximately $7.2 million equivalent as of
December 31, 2009), with interest computed on any outstanding borrowings at a
rate equal to the lender’s Basis Rate plus 0.75%. The European Credit Agreement
is cancellable by either party with 14 business days notice and contains
standard provisions in the event of default. As of December 31, 2009, we had no
borrowings pursuant to the European Credit Agreement.
F-25
Senior
Notes
Each of our
issuances of senior notes (collectively, the Senior Notes) are governed by the
terms of the Master Note Purchase Agreement dated September 2004, as
supplemented, or the Note Purchase Agreement dated April 2008. We may prepay the
Senior Notes, in whole or in part, at any time at a price equal to 100% of the
principal amount outstanding, plus accrued and unpaid interest and a
“make-whole” prepayment premium. The Senior Notes are unsecured and are
guaranteed by substantially all of our wholly owned U.S. subsidiaries. The Note
Purchase Agreement and Master Note Purchase Agreement, as supplemented, contain
customary covenants and restrictions, require us to maintain certain financial
ratios, and contain customary default provisions, as well as a cross-default
provision relating to any other of our indebtedness of $20 million or more. We
are in compliance with all covenants and conditions of the Note Purchase
Agreement and Master Note Purchase Agreement as of December 31, 2009. Upon the
occurrence and during the continuation of an event of default under the Note
Purchase Agreement and Master Note Purchase Agreement, as supplemented, the
Senior Notes may become immediately due and payable, either automatically or by
declaration of holders of more than 50% in principal amount of the Senior Notes
outstanding at the time.
NOTE
I — DECOMMISSIONING AND OTHER ASSET RETIREMENT OBLIGATIONS
The large majority
of our asset retirement obligations consists of the future well abandonment and
decommissioning costs for offshore oil and gas properties and platforms owned by
our Maritech subsidiary. The amount of decommissioning liabilities recorded by
Maritech is reduced by amounts allocable to joint interest owners, anticipated
insurance recoveries, and any contractual amount to be paid by the previous
owner of the oil and gas property when the liabilities are satisfied. We also
operate facilities in various U.S. and foreign locations that are used in the
manufacture, storage, and sale of our products, inventories, and equipment,
including offshore oil and gas production facilities and equipment. These
facilities are a combination of owned and leased assets. We are required to take
certain actions in connection with the retirement of these assets. We have
reviewed our obligations in this regard in detail and estimated the cost of
these actions. These estimates are the fair values that have been recorded for
retiring these long-lived assets. The associated asset retirement costs are
capitalized as part of the carrying amount of the long-lived asset. The costs
are depreciated on a straight-line basis over the life of the asset for non-oil
and gas assets and on a unit of production basis for oil and gas
properties.
The changes in the
asset retirement obligations during the most recent two year period are
as
follows:
|
Year
Ended December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(In
Thousands)
|
||||||||
|
Beginning
balance for the period, as reported
|
$ | 248,725 | $ | 199,506 | ||||
|
Activity in
the period:
|
||||||||
|
Accretion
of liability
|
7,893 | 7,084 | ||||||
|
Retirement
obligations incurred
|
1,326 | 20,274 | ||||||
|
Revisions
in estimated cash flows
|
47,069 | 43,034 | ||||||
|
Settlement
of retirement obligations
|
(80,903 | ) | (21,173 | ) | ||||
|
Ending
balance at December 31
|
$ | 224,110 | $ | 248,725 | ||||
NOTE
J — COMMITMENTS AND CONTINGENCIES
Litigation
We
are named defendants in several lawsuits and respondents in certain governmental
proceedings arising in the ordinary course of business. While the outcome of
lawsuits or other proceedings against us cannot be predicted with certainty,
management does not reasonably expect these matters to have a material adverse
impact on the financial statements.
F-26
Insurance Litigation –
Through December 31, 2009, we have expended approximately $55.2 million
of well intervention and debris removal work primarily associated with the three
Maritech offshore platforms and associated wells which were destroyed as a
result of Hurricanes Katrina and Rita in 2005. As a result of submitting claims
associated with well intervention costs expended during 2006 and 2007 and
responding to underwriters’ requests for additional information, approximately
$28.9 million of these well intervention costs were reimbursed; however, our
insurance underwriters maintained that well intervention costs for certain of
the damaged wells did not qualify as covered costs and certain well intervention
costs for qualifying wells were not covered under the policy. In addition, the
underwriters also maintained that there was no additional coverage provided
under an endorsement we obtained in August 2005 for the cost of debris removal
associated with these platforms or for other damage repairs associated with
Hurricanes Katrina and Rita on certain properties in excess of the insured
values provided by the property damage section of the policy. Although we
provided requested information to the underwriters and had numerous discussions
with the underwriters, brokers, and insurance adjusters, we did not receive the
requested reimbursement for these contested costs. As a result, on November 16,
2007, we filed a lawsuit in Montgomery County, Texas, entitled
Maritech Resources, Inc. v. Certain
Underwriters and Insurance Companies at Lloyd’s, London subscribing to Policy
no. GA011150U and Steege Kingston
, in which we sought damages for breach
of contract and various related claims and a declaration of the extent of
coverage of an endorsement to the policy. We also made an alternative claim
against our insurance broker, based on its procurement of the August 2005
endorsement, and a separate claim against underwriters’ insurance adjuster for
its role in handling the insurance claim. During the fourth quarter of 2007, we
reversed the anticipated insurance recoveries previously included in estimating
Maritech’s decommissioning liability, increasing the decommissioning liability
to $48.4 million for well intervention and debris removal work to be performed,
assuming no insurance reimbursements would be received. In addition, we reversed
a portion of our anticipated insurance recoveries previously included in
accounts receivable related to certain damage repair costs incurred. As a result
of the increase to the decommissioning liability, certain capitalized costs were
not realizable, resulting in impairments in accordance with the successful
efforts method of accounting. See Note B – Summary of Significant Accounting
Policies,
Oil and Gas
Properties
for further discussion.
During October
2009, we entered into a settlement agreement with regard to this lawsuit, under
which we received approximately $40.0 million during the fourth quarter of 2009
associated with the 2005 endorsement and well intervention costs incurred or to
be incurred from Hurricanes Katrina and Rita. Except for approximately $0.6
million of proceeds expected to be received in March 2010, no significant
additional insurance recoveries of well intervention, debris removal, or excess
property damage costs associated with Hurricanes Katrina and Rita will be
received. Following the collection of these amounts, we have collected
approximately $136.6 million of insurance proceeds associated with damage from
Hurricanes Katrina and Rita. This amount represents substantially all of the
maximum coverage limits pursuant to our policies. We estimate that future repair
and well intervention, abandonment, decommissioning, and debris removal efforts
related to these destroyed platforms will result in approximately $45 million to
$50 million of additional costs, and an estimate of these costs has been accrued
for as part of Maritech’s decommissioning liability. As a result of the
resolution of this contingency, the full amount of settlement proceeds is
reflected as a credit to earnings in the fourth quarter of 2009.
Class Action Lawsuit -
Between
March 27, 2008 and April 30, 2008, two putative class action complaints were
filed in the United States District Court for the Southern District of Texas
(Houston Division) against us and certain of our officers by certain
stockholders on behalf of themselves and other stockholders who purchased our
common stock between January 3, 2007 and October 16, 2007. The complaints assert
claims under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, as
amended, and Rule 10b-5 promulgated thereunder. The complaints allege that the
defendants violated the federal securities laws during the period by, among
other things, disseminating false and misleading statements and/or concealing
material facts concerning our current and prospective business and financial
results. The complaints also allege that, as a result of these actions, our
stock price was artificially inflated during the class period, which enabled our
insiders to sell their personally-held shares for a substantial gain. The
complaints seek unspecified compensatory damages, costs, and expenses. On May 8,
2008, the Court consolidated these complaints as
In re TETRA Technologies, Inc.
Securities Litigation,
No. 4:08-cv-0965 (S.D. Tex.). On August 27, 2008,
Lead Plaintiff Fulton County Employees’ Retirement System filed its Amended
Consolidated Complaint. On October 28, 2008, we filed a motion to dismiss the
federal class action. On July 9, 2009, the Court issued an opinion dismissing,
without prejudice, most of the claims in this lawsuit but permitting plaintiffs
to proceed on their allegations regarding disclosures pertaining to the
collectability of certain insurance receivables.
F-27
Between May 28,
2008 and June 27, 2008, two petitions were filed by alleged stockholders in the
District Courts of Harris County, Texas, 133
rd
and
113
th
Judicial Districts, purportedly on our behalf. The suits name our directors and
certain officers as defendants. The factual allegations in these lawsuits mirror
those in the class action lawsuit, and the claims are for breach of fiduciary
duty, unjust enrichment, abuse of control, gross mismanagement and waste of
corporate assets. The petitions seek disgorgement, costs, expenses and
unspecified equitable relief. On September 22, 2008, the 133
rd
District Court consolidated these complaints as
In re TETRA Technologies, Inc.
Derivative Litigation,
Cause No. 2008-23432 (133
rd
Dist. Ct., Harris County, Tex.), and appointed Thomas Prow and Mark Patricola as
Co-Lead Plaintiffs. This lawsuit was stayed by agreement of the parties pending
the Court’s ruling on our motion to dismiss the federal class action. On
September 8, 2009, the plaintiffs in this state court action filed a
consolidated petition which makes factual allegations similar to the surviving
allegations in the federal lawsuit.
At this stage, it is impossible to predict the
outcome of these proceedings or their impact upon us. We currently believe that
the allegations made in the federal complaints and state petitions are without
merit, and we intend to seek dismissal of and vigorously defend against these
actions. While a successful outcome cannot be guaranteed, we do not reasonably
expect these lawsuits to have a material adverse effect.
Environmental
One of our
subsidiaries, TETRA Micronutrients, Inc. (TMI), previously owned and operated a
production facility located in Fairbury, Nebraska. TMI is subject to an
Administrative Order on Consent issued to American Microtrace, Inc. (n/k/a/
TETRA Micronutrients, Inc.) in the proceeding styled
In the Matter of American Microtrace
Corporation
, EPA I.D. No. NED00610550, Respondent, Docket No.
VII-98-H-0016, dated September 25, 1998 (the Consent Order), with regard to the
Fairbury facility. TMI is liable for 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.
In
August of 2009, the Environmental Protection Agency (EPA), pursuant to Sections
308 and 311 of the Clean Water Act (CWA), served a request for information with
regard to a spill of zinc bromide that occurred on the Mississippi River on
March 11, 2009. We timely filed a response to that request for information in
August 2009. In January 2010, the EPA issued a Notice of Violation and
Opportunity to Show Cause related to the spill. We expect to meet with
the EPA soon to discuss potential violations and penalties. It has been
agreed that no injunctive relief will be required. Though penalties have not yet
been discussed, it is possible that they will exceed $100,000.
Product
Purchase Obligations
In the normal course of
our Fluids Division operations, we enter into supply agreements with certain
manufacturers of various raw materials and finished products. Some of these
agreements have terms and conditions that specify a minimum or maximum level of
purchases over the term of the agreement. Other agreements require us to
purchase the entire output of the raw material or finished product produced by
the manufacturer. Our purchase obligations under these agreements apply only
with regard to raw materials and finished products that meet specifications set
forth in the agreements. We recognize a liability for the purchase of such
products at the time we receive them. During 2006, we significantly increased
our purchase obligations as a result of the execution of a long-term supply
agreement with Chemtura Corporation. As of December 31, 2009, the aggregate
amount of the fixed and determinable portion of the purchase obligation pursuant
to our Fluids Division’s supply agreements was approximately $278.6 million,
including $12.6 million during 2010, $13.9 million during 2011, $15.3 million
during 2012, $15.3 million during 2013, $15.3 million during 2014, and $206.3
million thereafter, extending through 2029. Amounts purchased under these
agreements for each of the years ended December 31, 2009, 2008, and 2007 was
$6.5 million, $19.2 million, and $16.7 million, respectively.
NOTE
K — CAPITAL STOCK
Our Restated Certificate of Incorporation
authorizes us to issue 100,000,000 shares of common stock, par value $.01 per
share, and 5,000,000 shares of preferred stock, par value $.01 per share. As of
December 31, 2009, we had 75,542,282 shares of common stock outstanding, with
1,497,346 shares held in treasury, and no shares of preferred stock outstanding.
The voting, dividend, and liquidation rights of the
F-28
holders of common
stock are subject to the rights of the holders of preferred stock. The holders
of common stock are entitled to one vote for each share held. There is no
cumulative voting. Dividends may be declared and paid on common stock as
determined by our Board of Directors, subject to any preferential dividend
rights of any then outstanding preferred stock.
Our Board of Directors is empowered, without
approval of the stockholders, to cause shares of preferred stock to be issued in
one or more series and to establish the number of shares to be included in each
such series and the rights, powers, preferences and limitations of each series.
Because the Board of Directors has the power to establish the preferences and
rights of each series, it may afford the holders of any series of preferred
stock preferences, powers and rights, voting or otherwise, senior to the rights
of holders of common stock. The issuance of the preferred stock could have the
effect of delaying or preventing a change in control of the Company. See Note T
– Stockholders’ Rights Plan for a discussion of our stockholders’ rights plan,
as amended.
Upon our
dissolution or liquidation, whether voluntary or involuntary, holders of our
common stock will be entitled to receive all of our assets available for
distribution to our stockholders, subject to any preferential rights of any then
outstanding preferred stock.
In January 2004, our Board of Directors
authorized the repurchase of up to $20.0 million of our common stock. During the
three years ending December 31, 2009, we made no purchases of our common stock
pursuant to this authorization.
NOTE
L — EQUITY-BASED COMPENSATION
We
have various equity incentive compensation plans which provide for the granting
of restricted common stock, options for the purchase of our common stock, and
other performance-based equity-based compensation awards to our executive
officers, key employees, nonexecutive officers, consultants, and directors.
Incentive stock options are exercisable for periods up to ten years.
Compensation cost for all share-based payments is based on the grant date fair
value and recognized in earnings over the requisite service period. Total
equity-based compensation expense for the three years ended December 31, 2009,
2008, and 2007 was $6.7 million, $5.9 million, and $4.4 million, respectively,
which approximated the fair value of equity-based compensation awards vesting
during the periods. This expense reduced net income by $4.4 million, $3.7
million, and $2.8 million and reduced basic and diluted earnings per share by
$0.06, $0.05 and $0.04, respectively, for the three years ended December 31,
2009, 2008, and 2007.
The Black-Scholes
option-pricing model is used to estimate option fair values. This option-pricing
model requires a number of assumptions, of which the most significant are:
expected stock price volatility, the expected pre-vesting forfeiture rate, and
the expected option term (the amount of time from the grant date until the
options are exercised or expire). Expected volatility was calculated based upon
actual historical stock price movements over the most recent periods ending
December 31, 2009 equal to the expected option term. Expected pre-vesting
forfeitures were estimated based on actual historical pre-vesting forfeitures
over the most recent periods ending December 31, 2009 for the expected option
term.
The TETRA
Technologies, Inc. 1990 Stock Option Plan (the 1990 Plan) was initially adopted
in 1985 and subsequently amended to change the name, the number, and the type of
options that could be granted as well as the time period for granting stock
options. As of December 31, 2004, no further options may be granted under the
1990 Plan. We granted performance stock options under the 1990 Plan to certain
executive officers. These granted options have an exercise price per share of
not less than the market value at the date of issuance and are fully vested and
exercisable.
In
1993, we adopted the TETRA Technologies, Inc. Director Stock Option Plan (the
Directors’ Plan). In 1996, the Directors’ Plan was amended to increase the
number of shares issuable under automatic grants thereunder. In 1998, we adopted
the TETRA Technologies, Inc. 1998 Director Stock Option Plan as amended (the
1998 Director Plan). The purpose of the Directors’ Plan and the 1998 Director
Plan (together the Director Stock Option Plans) is to enable us to attract and
retain qualified individuals to serve as our directors and to align their
interests more closely with our interests. The 1998 Director Plan is funded with
our treasury stock and was amended and restated effective December 18, 2002 to
increase the number of shares issuable thereunder, to change the types of
options that may be granted thereunder, and to increase the number of shares
issuable under automatic grants thereunder. The 1998 Director Plan was amended
and restated
F-29
effective June 27,
2003, and was further amended in December 2005 to increase the number of shares
issuable thereunder. As of May 2, 2006, no further options may be granted under
the Director Stock Option Plans.
During 1996, we
adopted the 1996 Stock Option Plan for Nonexecutive Employees and Consultants
(the Nonqualified Plan) to enable us to award nonqualified stock options to
nonexecutive employees and consultants who are key to our performance.
As of May 2, 2006, no
further options may be granted under the Nonqualified Plan.
In
May 2006, our stockholders approved the adoption of the TETRA Technologies, Inc.
2006 Equity Incentive Compensation Plan. Pursuant to the TETRA Technologies,
Inc. 2006 Equity Incentive Compensation Plan, we were authorized to grant up to
1,300,000 shares in the form of stock options (including incentive stock options
and nonqualified stock options); restricted stock; bonus stock; stock
appreciation rights; and performance awards to employees, consultants, and
non-employee directors. As a result of the May, 2006 adoption and approval of
the TETRA Technologies, Inc. 2006 Equity Incentive Compensation Plan, no further
awards may be granted under our other previously existing plans. As of May 4,
2008, no further awards may be granted under the TETRA Technologies, Inc. 2006
Equity Incentive Compensation Plan.
In
May 2007, our stockholders approved the adoption of the TETRA Technologies, Inc.
2007 Equity Incentive Compensation Plan. In May 2008, our stockholders approved
the adoption of the TETRA Technologies, Inc. Amended and Restated 2007 Equity
Incentive Compensation Plan, which among other changes, resulted in an increase
in the maximum number of shares authorized for issuance. Pursuant to the TETRA
Technologies, Inc. Amended and Restated 2007 Equity Incentive Compensation Plan,
we are authorized to grant up to 4,590,000 shares in the form of stock options
(including incentive stock options and nonqualified stock options); restricted
stock; bonus stock; stock appreciation rights; and performance awards to
employees, consultants and non-employee directors.
Grants
of Restricted Common Stock
During each of the
three years ended December 31, 2009, we granted to certain officers and
employees restricted shares, which generally vest over a three to five year
period. During 2009, we granted a total of 98,053 restricted shares, having an
average market value (equal to the closing price of the common stock on the
dates of grant) of $8.07 per share, or an aggregate market value of $0.8
million. During 2008, we granted a total of 216,901 restricted shares, having an
average market value (equal to the quoted closing price of the common stock on
the dates of grant) of $19.51 per share, or an aggregate market value of $4.2
million, at the date of grant. During 2007, we granted a total of 258,750
restricted shares, having an average market value of $27.66 per share, or an
aggregate market value of approximately $7.2 million, at the date of
grant.
The following is a
summary of restricted stock activity for the year ended December 31,
2009:
|
Shares
|
Weighted
Average Grant Date Fair Value Per Share
|
|||||||
|
(In
Thousands)
|
||||||||
|
Nonvested
restricted shares outstanding at December 31, 2008
|
352 | $ | 23.39 | |||||
|
Shares
granted
|
98 | 8.07 | ||||||
|
Shares
cancelled
|
(15 | ) | 24.29 | |||||
|
Shares
vested
|
(152 | ) | 17.60 | |||||
|
Nonvested
restricted shares outstanding at December 31, 2009
|
283 | $ | 21.16 | |||||
F-30
Grants
of Options to Purchase Common Stock
Stock options
authorized for issuance, outstanding and currently exercisable at December 31,
2009, 2008, and 2007 are as follows:
|
2009
|
2008
|
2007
|
||||||||||
|
(In
Thousands, Except Per Share Amounts)
|
||||||||||||
|
TETRA Technologies, Inc. Amended and Restated 2007
Equity
|
||||||||||||
|
Incentive Compensation
Plan
|
||||||||||||
|
Maximum
number of shares authorized for issuance
|
4,590 | 4,590 | 90 | |||||||||
|
Shares
reserved for future grants
|
931 | 2,908 | 63 | |||||||||
|
Options
exercisable at period end
|
469 | 6 | 6 | |||||||||
|
Weighted
average exercise price of options exercisable
|
||||||||||||
|
at
period end
|
$ | 19.90 | $ | 18.50 | $ | 18.50 | ||||||
|
TETRA Technologies, Inc. 2006 Equity Incentive
Compensation Plan
|
||||||||||||
|
Maximum
number of shares authorized for issuance
|
1,300 | 1,300 | 1,300 | |||||||||
|
Shares
reserved for future grants
|
- | - | 48 | |||||||||
|
Options
exercisable at period end
|
359 | 320 | 257 | |||||||||
|
Weighted
average exercise price of options exercisable
|
||||||||||||
|
at
period end
|
$ | 27.04 | $ | 26.86 | $ | 26.61 | ||||||
|
1990 TETRA Technologies, Inc. Employee Plan (as
amended)
|
||||||||||||
|
Maximum
number of shares authorized for issuance
|
17,775 | 17,775 | 17,775 | |||||||||
|
Shares
reserved for future grants
|
- | - | - | |||||||||
|
Options
exercisable at period end
|
1,290 | 1,395 | 1,955 | |||||||||
|
Weighted
average exercise price of options exercisable
|
||||||||||||
|
at
period end
|
$ | 7.43 | $ | 7.09 | $ | 6.52 | ||||||
|
Director Stock Option Plans (as
amended)
|
||||||||||||
|
Maximum
number of shares authorized for issuance
|
2,138 | 2,138 | 2,138 | |||||||||
|
Shares
reserved for future grants
|
- | - | - | |||||||||
|
Options
exercisable at period end
|
144 | 297 | 342 | |||||||||
|
Weighted
average exercise price of options exercisable
|
||||||||||||
|
at
period end
|
$ | 15.26 | $ | 12.09 | $ | 11.74 | ||||||
|
All Other Plans
|
||||||||||||
|
Maximum
number of shares authorized for issuance
|
3,615 | 3,615 | 3,615 | |||||||||
|
Shares
reserved for future grants
|
- | - | - | |||||||||
|
Options
exercisable at period end
|
870 | 842 | 936 | |||||||||
|
Weighted
average exercise price of options exercisable
|
||||||||||||
|
at
period end
|
$ | 14.40 | $ | 13.85 | $ | 12.13 | ||||||
The following is a
summary of options outstanding and options exercisable as of December 31,
2009:
|
Options
Outstanding
|
Options
Exercisable
|
|||||||||||||||||||||||||
|
Weighted
|
Weighted
|
Weighted
|
Weighted
|
|||||||||||||||||||||||
|
Average
|
Average
|
Average
|
Average
|
|||||||||||||||||||||||
|
Range
of
|
Remaining
|
Exercise
|
Remaining
|
Exercise
|
||||||||||||||||||||||
|
Exercise
Price
|
Shares
|
Contracted
Life
|
Price
|
Shares
|
Contracted
Life
|
Price
|
||||||||||||||||||||
|
(In
Thousands)
|
(In
Years)
|
(In
Thousands)
|
(In
Years)
|
|||||||||||||||||||||||
| $1.61 to $4.07 | 1,966 | 8.3 | $ | 3.72 | 235 | 2.0 | $ | 3.29 | ||||||||||||||||||
| $4.08 to $8.11 | 608 | 3.8 | $ | 4.74 | 498 | 2.6 | $ | 4.83 | ||||||||||||||||||
| $8.12 to $9.21 | 1,241 | 2.9 | $ | 9.09 | 1,232 | 2.9 | $ | 9.10 | ||||||||||||||||||
| $9.22 to $20.85 | 333 | 4.0 | $ | 15.78 | 283 | 3.2 | $ | 15.80 | ||||||||||||||||||
| $20.86 to $30.00 | 1,862 | 7.5 | $ | 22.85 | 883 | 6.8 | $ | 23.80 | ||||||||||||||||||
| 6,010 | 6.2 | $ | 11.53 | 3,131 | 3.9 | $ | 12.74 | |||||||||||||||||||
F-31
The following is a
summary of stock option activity for the year ended December 31,
2009:
|
Weighted
Average
|
||||||||
|
Option
Price
|
||||||||
|
Shares
Under Option
|
Per
Share
|
|||||||
|
(In
Thousands)
|
||||||||
|
Outstanding
at December 31, 2008
|
4,590 | $ | 14.80 | |||||
|
Options
granted
|
1,948 | 3.88 | ||||||
|
Options
cancelled
|
(324 | ) | 15.39 | |||||
|
Options
exercised
|
(204 | ) | 5.90 | |||||
|
Outstanding
at December 31, 2009
|
6,010 | $ | 11.53 | |||||
The total intrinsic
value, or the difference between the exercise price and the market price on the
date of exercise, of all options exercised during the three years ended December
31, 2009, 2008, and 2007 was approximately $0.8 million, $5.3 million and $43.2
million, respectively. The intrinsic value of options outstanding as of December
31, 2009 was $20.8 million, and the intrinsic value of options exercisable as of
December 31, 2009 was $7.4 million. Cash received from stock options exercised
during the three years ended December 31, 2009, 2008, and 2007 was $1.2 million,
$4.7 million and $12.1 million, respectively. Recognized excess tax benefits
related to the exercise of stock options during the three years ended December
31, 2009, 2008, and 2007 were $0.2 million, $1.5 million and $13.2 million,
respectively.
The fair value of
each option grant is estimated on the date of grant using the Black-Scholes
option pricing model with the following assumptions used for each of the three
years ended December 31, 2009:
|
Year
Ended December 31,
|
|||||
|
2009
|
2008
|
2007
|
|||
|
Expected
stock price volatility
|
65% to
73%
|
32% to
57%
|
31% to
36%
|
||
|
Expected life
of options
|
4.7
years
|
4.4 to 4.8
years
|
3.4 to 4.3
years
|
||
|
Risk free
interest rate
|
1.9% to
2.6%
|
1.5% to
3.9%
|
4.3% to
5.0%
|
||
|
Expected
dividend yield
|
-
|
-
|
-
|
||
The weighted
average fair value of options granted during the years ended December 31, 2009,
2008 and 2007, using the Black-Scholes model, was $2.73, $7.61, and $7.74 per
share, respectively. Total estimated unrecognized compensation cost from
unvested stock options and restricted stock as of December 31, 2009 was
approximately $15.0 million, which is expected to be recognized over a weighted
average period of approximately 2.4 years.
Certain options
exercised during 2008 and 2007 were exercised through the surrender
of 26,304 and 4,655 shares, respectively, of our common stock previously owned
by the option holder for a period of at least six months prior to exercise. In
addition, during 2009, 2008, and 2007, we received 6,318, 8,119 and 27,784
shares, respectively, of our common stock related to the vesting of certain
employee restricted stock. Such surrendered shares received by us are included
in treasury stock. At December 31, 2009, net of options previously exercised
pursuant to our various stock option plans, we have a maximum of 7,224,063
shares of common stock issuable pursuant to stock options previously granted and
outstanding and stock options authorized to be granted in the
future.
NOTE
M — 401(k) PLAN
We have a 401(k) retirement plan (the Plan)
that covers substantially all employees and entitles them to contribute up to
70% of their annual compensation, subject to maximum limitations imposed by the
Internal Revenue Code. We have historically matched 50% of each employee’s
contribution up to 6% of annual compensation, subject to certain limitations as
outlined in the Plan. Beginning in February 2009, we suspended company matching
of employee contributions, although company matching resumed effective January
2, 2010. In addition, we can make discretionary contributions which are
allocable to participants in accordance with the Plan. Total expense related to
our 401(k) plan was $0.7 million, $3.3 million, and $2.7 million in 2009, 2008,
and 2007, respectively.
F-32
NOTE
N — DEFERRED COMPENSATION PLAN
We provide our officers, directors, and certain
key employees with the opportunity to participate in an unfunded, deferred
compensation program. There were thirty-one participants in the program at
December 31, 2009. Under the program, participants may defer up to 100% of their
yearly total cash compensation. The amounts deferred remain our sole property,
and we use a portion of the proceeds to purchase life insurance policies on the
lives of certain of the participants. The insurance policies, which also remain
our sole property, are payable to us upon the death of the insured. We
separately contract with the participant to pay to the participant the amount of
deferred compensation, as adjusted for gains or losses, invested in
participant-selected investment funds. Participants may elect to receive
deferrals and earnings at termination, death, or at a specified future date
while still employed. Distributions while employed must be at least three years
after the deferral election. The program is not qualified under Section 401 of
the Internal Revenue Code. At December 31, 2009, the amounts payable under the
plan approximated the value of the corresponding assets we owned.
NOTE
O — HEDGE CONTRACTS
We
are exposed to financial and market risks that affect our businesses. We have
market risk exposure in the sales prices we receive for our oil and gas
production. We have currency exchange rate risk exposure related to specific
transactions denominated in a foreign currency as well as to investments in
certain of our international operations. As a result of our variable rate bank
credit facility, to the extent we have debt outstanding, we may face market risk
exposure related to changes in applicable interest rates. We have concentrations
of credit risk as a result of trade receivables from companies in the energy
industry. Our financial risk management activities involve, among other
measures, the use of derivative financial instruments, such as swap and collar
agreements, to hedge the impact of market price risk exposures for a significant
portion of our oil and gas production and for certain foreign currency
transactions. We are exposed to the volatility of oil and gas prices for the
portion of our oil and gas production that is not hedged. We formally document
all relationships between hedging instruments and hedged items, as well as our
risk management objectives, our strategies for undertaking various hedge
transactions, and our methods for assessing and testing correlation and hedge
ineffectiveness. All hedging instruments are linked to the hedged asset,
liability, firm commitment, or forecasted transaction. We also assess, both at
the inception of the hedge and on an ongoing basis, whether the derivatives that
are used in these hedging transactions are highly effective in offsetting
changes in cash flows of the hedged items.
Derivative
Hedge Contracts
As of December 31,
2009, we had the following cash flow hedging swap contracts outstanding relating
to a portion of our Maritech subsidiary’s oil and gas production:
|
Derivative
Contracts
|
Aggregate
Daily
Volume
|
Weighted
Average Contract Price
|
Contract
Year
|
|||
|
Natural gas
swap contracts
|
20,000
MMBtu/day
|
$8.147/MMBtu
|
2010
|
|||
|
Oil swap
contracts
|
2,000
Bbls/day
|
$78.70/Bbl
|
2010
|
During the second
quarter of 2009, we liquidated certain cash flow hedging swap contracts
associated with Maritech’s oil production in exchange for cash of approximately
$23.1 million. The summary above includes a natural gas swap contract for 10,000
MMBtu/day of 2010 production at a contract price of $6.03/MMBtu and an oil swap
contract for 2,000 barrels/day of 2010 production at a contract price of
$78.70/barrel, both of which were added during 2009. In January 2010, we entered
into an additional oil swap contract for 1,000 barrels/day of 2010 production,
beginning February 2010, at a contract price of $84.90/barrel.
We
believe that our swap agreements are “highly effective cash flow hedges” in
managing the volatility of future cash flows associated with our oil and gas
production. The effective portion of the change in the derivative’s fair value
(i.e., that portion of the change in the derivative’s fair value that offsets
the corresponding change in the cash flows of the hedged transaction) is
initially reported as a component of accumulated other comprehensive income,
which is classified within stockholders’ equity. This component of accumulated
other comprehensive income associated with cash flow hedge derivative contracts,
including those derivative contracts which have been liquidated, will be
subsequently reclassified into product sales
F-33
revenues, utilizing
the specific identification method, when the hedged exposure affects earnings
(i.e., when hedged oil and gas production volumes are reflected in revenues). As
of December 31, 2009, the total balance (approximately $23.5 million) of
accumulated other comprehensive income associated with cash flow hedge
derivatives is expected to be reclassified into product sales revenue in the
subsequent twelve month period. Any “ineffective” portion of the change in the
derivative’s fair value is recognized in earnings immediately.
The fair value of
hedging instruments reflects our best estimate and is based upon exchange or
over-the-counter quotations, whenever they are available. Quoted valuations may
not be available. Where quotes are not available, we utilize other valuation
techniques or models to estimate fair values. These modeling techniques require
us to make estimations of future prices, price correlation, and market
volatility and liquidity. The actual results may differ from these estimates,
and these differences can be positive or negative. The fair values of our oil
and natural gas swap contracts as of December 31, 2009 and 2008 are as
follows:
|
Balance
Sheet
|
Fair
Value at December 31,
|
||||||||
|
Derivatives
designated as hedging
|
Location
|
2009
|
2008
|
||||||
|
instruments
|
(In
Thousands)
|
||||||||
|
Natural gas
swap contracts
|
Current
assets
|
$ | 19,926 | $ | 25,031 | ||||
|
Oil swap
contracts
|
Current
assets
|
- | 13,021 | ||||||
|
Natural gas
swap contracts
|
Long-term
assets
|
- | 10,628 | ||||||
|
Oil swap
contracts
|
Long-term
assets
|
- | 28,470 | ||||||
|
Oil swap
contracts
|
Current
liabilities
|
(2,618 | ) | - | |||||
|
Oil swap
contracts
|
Long-term
liabilities
|
- | - | ||||||
|
Total
derivatives designated as hedging
|
|||||||||
|
instruments
|
$ | 17,308 | $ | 77,150 | |||||
Oil and natural gas
swap assets and liabilities which are classified as current assets or
liabilities relate to the portion of the derivative contracts associated with
hedged oil and gas production to occur over the next twelve month period. None
of the oil and natural gas swap contracts contain credit risk related contingent
features that would require us to post assets as collateral for contracts that
are classified as liabilities.
As
the hedge contracts were highly effective, the effective portion of the gain,
net of taxes, from changes in contract fair value, including the gain on the
liquidated oil swap contracts, is included in accumulated other comprehensive
income within stockholders’ equity as of December 31, 2009. Pretax gains and
losses associated with oil and gas derivative swap contracts for each of the
three years ended December 31, 2009, 2008, and 2007 are summarized
below:
|
Year
Ended December 31, 2009
|
||||||||||||
|
Oil
|
Natural
Gas
|
Total
|
||||||||||
|
(In
Thousands)
|
||||||||||||
|
Derivative
swap contracts
|
||||||||||||
|
Amount of
pretax gain reclassified from accumulated other
comprehensive
|
||||||||||||
|
income
into product sales revenue (effective portion)
|
$ | 6,978 | $ | 40,054 | $ | 47,032 | ||||||
|
Amount of
pretax gain (loss) from change in derivative fair value
|
||||||||||||
|
recognized
in other comprehensive income
|
(13,966 | ) | 22,906 | 8,940 | ||||||||
|
Amount of
pretax gain (loss) recognized in other income (expense)
|
||||||||||||
|
(ineffective
portion)
|
(408 | ) | (1,321 | ) | (1,729 | ) | ||||||
|
Year
Ended December 31, 2008
|
||||||||||||
|
Oil
|
Natural
Gas
|
Total
|
||||||||||
|
(In
Thousands)
|
||||||||||||
|
Derivative
swap contracts
|
||||||||||||
|
Amount of
pretax gain reclassified from accumulated other
comprehensive
|
||||||||||||
|
income
into product sales revenue (effective portion)
|
$ | 42,462 | $ | 14,255 | $ | 56,717 | ||||||
|
Amount of
pretax gain (loss) from change in derivative fair value
|
||||||||||||
|
recognized
in other comprehensive income
|
52,151 | 18,948 | 71,099 | |||||||||
|
Amount of
pretax gain (loss) recognized in other income (expense)
|
||||||||||||
|
(ineffective
portion)
|
1,768 | 6,862 | 8,630 | |||||||||
F-34
|
Year
Ended December 31, 2007
|
||||||||||||
|
Oil
|
Natural
Gas
|
Total
|
||||||||||
|
(In
Thousands)
|
||||||||||||
|
Derivative
swap contracts
|
||||||||||||
|
Amount of
pretax gain (loss) reclassified from accumulated other
comprehensive
|
||||||||||||
|
income
into product sales revenue (effective portion)
|
$ | 5,277 | $ | (3,102 | ) | $ | 2,175 | |||||
|
Amount of
pretax gain (loss) from change in derivative fair value
|
||||||||||||
|
recognized
in other comprehensive income
|
(63,261 | ) | 4,264 | (58,997 | ) | |||||||
|
Amount of
pretax gain (loss) recognized in other income (expense)
|
||||||||||||
|
(ineffective
portion)
|
- | 165 | 165 | |||||||||
The cash flow
hedging swap contracts that were liquidated during the second quarter of 2009
met the effectiveness requirements to be accounted for as hedges, and as a
result, the gain on the liquidated swap contracts was retained in other
comprehensive income and the $23.1 million proceeds were classified as a cash
flow from operating activities in the accompanying statements of cash flows. Due
to the suspension of a portion of Maritech’s oil and gas production following
Hurricane Ike in September 2008, certain of our oil and natural gas swap
contracts associated with 2008 production no longer met the effectiveness
requirements to be accounted for as hedges. As a result, the portion of other
comprehensive income associated with these contracts was credited to earnings
during the third quarter of 2008. Also as a result of suspended Maritech
production, certain qualifying hedge contracts reflected ineffectiveness during
the third and fourth quarter of 2008. During the fourth quarter, we liquidated
each of the oil and natural gas swap contracts associated with 2008 production
in exchange for cash of $6.5 million. The associated cash flows from the 2008
liquidation of these ineffective contracts were classified as cash flows from
investing activities in the accompanying consolidated statements of cash
flows.
Other
Hedge Contracts
Transaction gains
and losses attributable to a foreign currency transaction that is designated as,
and is effective as, an economic hedge of a net investment in a foreign entity
is subject to the same accounting as translation adjustments. As such, the
effect of a rate change on a foreign currency hedge is the same as the
accounting for the effect of the rate change on the net foreign investment; both
are recorded in the cumulative translation account, a component of stockholders’
equity, and are partially or fully offsetting. Our long-term debt includes
borrowings which are designated as a hedge of our net investment in our European
calcium chloride operations. At December 31, 2009, we had 28.0 million euros
(approximately $40.1 million) designated as a hedge of a net investment in this
foreign operation. Changes in the foreign currency exchange rate have resulted
in a cumulative change to the cumulative translation adjustment account of $4.7
million, net of taxes, at December 31, 2009, with no ineffectiveness
recorded.
NOTE
P — INCOME (LOSS) PER SHARE
The following is a
reconciliation of the common shares outstanding with the number of shares used
in the computation of income per common and common equivalent
share:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(In
Thousands)
|
||||||||||||
|
Number of
weighted average common shares outstanding
|
75,045 | 74,519 | 73,573 | |||||||||
|
Assumed
exercise of stock options
|
677 | - | 2,348 | |||||||||
|
Average
diluted shares outstanding
|
75,722 | 74,519 | 75,921 | |||||||||
For the year ended
December 31, 2009, the average diluted shares outstanding excludes the impact of
3,185,388 of average outstanding stock options that have exercise prices in
excess of the average market price, as the inclusion of these shares would have
been antidilutive. For the year and the three month period ended December 31,
2008, all outstanding stock options were excluded from average diluted shares
outstanding, as the inclusion of these shares would have been antidilutive due
to the net loss recorded during the period. For the year ended December 31,
2007, the average diluted shares outstanding excludes the impact of 716,354 of
average outstanding stock options that have exercise prices in excess of the
average market price, as the inclusion of these shares would have been
antidilutive.
F-35
NOTE
Q — INDUSTRY SEGMENTS AND GEOGRAPHIC INFORMATION
We
manage our operations through five operating segments: Fluids, Offshore
Services, Maritech, Production Testing and Compressco. Beginning in the fourth
quarter of 2008, our Production Enhancement Division consists of two separate
reporting segments: the Production Testing segment, and the Compressco segment.
Segment information for 2007 has been revised to conform to the 2008 and 2009
presentation.
Our Fluids Division
manufactures and markets clear brine fluids, additives, and other associated
products and services to the oil and gas industry for use in well drilling,
completion, and workover operations both in the United States and in certain
regions of Latin America, Europe, Asia, and Africa. The Division also markets
liquid and dry calcium chloride manufactured at its production facilities to a
variety of markets outside the energy industry.
Our Offshore
Division consists of two operating segments: Offshore Services and Maritech, an
oil and gas exploration, exploitation, and production segment. The Offshore
Services segment provides (1) downhole and subsea services such as plugging and
abandonment, workover, and wireline services, (2) construction and
decommissioning services, including hurricane damage remediation, utilizing our
heavy lift barges and cutting technologies in the construction or
decommissioning of offshore oil and gas production platforms and pipelines, and
(3) diving services involving conventional and saturated air diving and the
operation of several dive support vessels.
The Maritech
segment consists of our Maritech Resources, Inc. (Maritech) subsidiary, which,
with its subsidiaries, is an oil and gas exploration and production company
focused in the offshore and onshore U.S. Gulf Coast region. Maritech
periodically acquires oil and gas properties in order to replenish or expand its
production operations and to provide additional development and exploitation
opportunities. The Offshore Division’s Offshore Services segment performs a
significant portion of the well abandonment and decommissioning services
required by Maritech.
Our Production
Enhancement Division consists of two operating segments: Production Testing and
Compressco. The Production Testing segment provides production testing services
in many of the major oil and gas basins in the United States, as well as onshore
basins in Mexico, Brazil, Northern Africa, the Middle East, and other
international markets.
The Compressco
segment provides wellhead compression-based production enhancement services
throughout many of the onshore producing regions of the United States, as well
as basins in Canada, Mexico, South America, Europe, Asia, and other
international locations. These compression services can improve the value of
natural gas and oil wells by increasing daily production and total recoverable
reserves.
We
generally evaluate performance and allocate resources based on profit or loss
from operations before income taxes and nonrecurring charges, return on
investment, and other criteria. Transfers between segments, as well as
geographic areas, are priced at the estimated fair value of the products or
services as negotiated between the operating units. “Corporate overhead”
includes corporate general and administrative expenses, corporate depreciation
and amortization, interest income and expense, and other income and
expense.
F-36
Summarized
financial information
concerning the business segments from
continuing operations is as
follows:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(In
Thousands)
|
||||||||||||
|
Revenues
from external customers
|
||||||||||||
|
Product
sales
|
||||||||||||
|
Fluids
Division
|
$ | 167,984 | $ | 227,194 | $ | 226,399 | ||||||
|
Offshore
Division
|
||||||||||||
|
Offshore
Services
|
2,970 | 4,328 | 4,860 | |||||||||
|
Maritech
|
174,191 | 207,180 | 213,338 | |||||||||
|
Intersegment
eliminations
|
- | - | - | |||||||||
|
Total
Offshore Division
|
177,161 | 211,508 | 218,198 | |||||||||
|
Production
Enhancement Division
|
||||||||||||
|
Production
Testing
|
- | - | - | |||||||||
|
Compressco
|
4,860 | 8,639 | 12,641 | |||||||||
|
Total
Production Enhancement Division
|
4,860 | 8,639 | 12,641 | |||||||||
|
Consolidated
|
$ | 350,005 | $ | 447,341 | $ | 457,238 | ||||||
|
Services and
rentals
|
||||||||||||
|
Fluids
Division
|
$ | 57,491 | $ | 65,602 | $ | 54,353 | ||||||
|
Offshore
Division
|
||||||||||||
|
Offshore
Services
|
304,729 | 279,019 | 306,174 | |||||||||
|
Maritech
|
2,848 | 1,329 | 816 | |||||||||
|
Intersegment
eliminations
|
- | - | - | |||||||||
|
Total
Offshore Division
|
307,577 | 280,348 | 306,990 | |||||||||
|
Production
Enhancement Division
|
||||||||||||
|
Production
Testing
|
80,556 | 126,996 | 92,989 | |||||||||
|
Compressco
|
83,248 | 88,778 | 70,913 | |||||||||
|
Total
Production Enhancement Division
|
163,804 | 215,774 | 163,902 | |||||||||
|
Consolidated
|
$ | 528,872 | $ | 561,724 | $ | 525,245 | ||||||
|
Intersegment
revenues
|
||||||||||||
|
Fluids
Division
|
$ | 42 | $ | 452 | $ | 1,322 | ||||||
|
Offshore
Division
|
||||||||||||
|
Offshore
Services
|
46,099 | 23,015 | 30,048 | |||||||||
|
Maritech
|
- | - | - | |||||||||
|
Intersegment
eliminations
|
(45,648 | ) | (22,971 | ) | (29,057 | ) | ||||||
|
Total
Offshore Division
|
451 | 44 | 991 | |||||||||
|
Production
Enhancement Division
|
||||||||||||
|
Production
Testing
|
1 | 23 | 141 | |||||||||
|
Compressco
|
- | - | - | |||||||||
|
Total
Production Enhancement Division
|
1 | 23 | 141 | |||||||||
|
Intersegment
eliminations
|
(494 | ) | (519 | ) | (2,454 | ) | ||||||
|
Consolidated
|
$ | - | $ | - | $ | - | ||||||
|
Total
revenues
|
||||||||||||
|
Fluids
Division
|
$ | 225,517 | $ | 293,248 | $ | 282,074 | ||||||
|
Offshore
Division
|
||||||||||||
|
Offshore
Services
|
353,798 | 306,362 | 341,082 | |||||||||
|
Maritech
|
177,039 | 208,509 | 214,154 | |||||||||
|
Intersegment
eliminations
|
(45,648 | ) | (22,971 | ) | (29,057 | ) | ||||||
|
Total
Offshore Division
|
485,189 | 491,900 | 526,179 | |||||||||
|
Production
Enhancement Division
|
||||||||||||
|
Production
Testing
|
80,557 | 127,019 | 93,130 | |||||||||
|
Compressco
|
88,108 | 97,417 | 83,554 | |||||||||
|
Total
Production Enhancement Division
|
168,665 | 224,436 | 176,684 | |||||||||
|
Intersegment
eliminations
|
(494 | ) | (519 | ) | (2,454 | ) | ||||||
|
Consolidated
|
$ | 878,877 | $ | 1,009,065 | $ | 982,483 | ||||||
F-37
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(In
Thousands)
|
||||||||||||
|
Depreciation,
depletion, amortization, and accretion
|
||||||||||||
|
Fluids
Division
|
$ | 15,281 | $ | 14,033 | $ | 12,758 | ||||||
|
Offshore
Division
|
||||||||||||
|
Offshore
Services
|
16,347 | 18,998 | 16,279 | |||||||||
|
Maritech
|
87,274 | 99,665 | 82,800 | |||||||||
|
Intersegment
eliminations
|
(506 | ) | (544 | ) | (891 | ) | ||||||
|
Total
Offshore Division
|
103,115 | 118,119 | 98,188 | |||||||||
|
Production
Enhancement Division
|
||||||||||||
|
Production
Testing
|
14,139 | 12,233 | 9,355 | |||||||||
|
Compressco
|
13,780 | 12,049 | 8,043 | |||||||||
|
Total
Production Enhancement Division
|
27,919 | 24,282 | 17,398 | |||||||||
|
Corporate
overhead
|
3,011 | 2,459 | 1,500 | |||||||||
|
Consolidated
|
$ | 149,326 | $ | 158,893 | $ | 129,844 | ||||||
|
Interest
expense
|
||||||||||||
|
Fluids
Division
|
$ | 116 | $ | 173 | $ | 159 | ||||||
|
Offshore
Division
|
||||||||||||
|
Offshore
Services
|
6 | 101 | 75 | |||||||||
|
Maritech
|
19 | 43 | 57 | |||||||||
|
Intersegment
eliminations
|
- | - | - | |||||||||
|
Total
Offshore Division
|
25 | 144 | 132 | |||||||||
|
Production
Enhancement Division
|
||||||||||||
|
Production
Testing
|
2 | 30 | 21 | |||||||||
|
Compressco
|
- | - | - | |||||||||
|
Total
Production Enhancement Division
|
2 | 30 | 21 | |||||||||
|
Corporate
overhead
|
13,064 | 17,210 | 17,574 | |||||||||
|
Consolidated
|
$ | 13,207 | $ | 17,557 | $ | 17,886 | ||||||
|
Income
(loss) before taxes and discontinued operations
|
||||||||||||
|
Fluids
Division
|
$ | 20,791 | $ | 5,401 | $ | 10,897 | ||||||
|
Offshore
Division
|
||||||||||||
|
Offshore
Services
|
78,394 | 3,019 | 33,496 | |||||||||
|
Maritech
|
22,012 | (31,932 | ) | (49,815 | ) | |||||||
|
Intersegment
eliminations
|
647 | (782 | ) | 6,225 | ||||||||
|
Total
Offshore Division
|
101,053 | (29,695 | ) | (10,094 | ) | |||||||
|
Production
Enhancement Division
|
||||||||||||
|
Production
Testing
|
17,690 | 35,677 | 25,639 | |||||||||
|
Compressco
|
23,563 | 30,310 | 26,663 | |||||||||
|
Total
Production Enhancement Division
|
41,253 | 65,987 | 52,302 | |||||||||
|
Corporate
overhead
|
(57,727 | ) (1) | (45,608 | ) (1) | (50,943 | ) (1) | ||||||
|
Consolidated
|
$ | 105,370 | $ | (3,915 | ) | $ | 2,162 | |||||
|
Total
assets
|
||||||||||||
|
Fluids
Division
|
$ | 375,754 | $ | 328,852 | $ | 285,882 | ||||||
|
Offshore
Division
|
||||||||||||
|
Offshore
Services
|
190,494 | 220,671 | 262,729 | |||||||||
|
Maritech
|
363,605 | 413,661 | 391,703 | |||||||||
|
Intersegment
eliminations
|
(2,246 | ) | (2,902 | ) | (2,119 | ) | ||||||
|
Total
Offshore Division
|
551,853 | 631,430 | 652,313 | |||||||||
|
Production
Enhancement Division
|
||||||||||||
|
Production
Testing
|
112,276 | 100,676 | 80,281 | |||||||||
|
Compressco
|
202,995 | 212,619 | 186,448 | |||||||||
|
Total
Production Enhancement Division
|
315,271 | 313,295 | 266,729 | |||||||||
|
Corporate
overhead
|
104,721 | (2) | 139,047 | (2) | 90,612 | (2) | ||||||
|
Consolidated
|
$ | 1,347,599 | $ | 1,412,624 | $ | 1,295,536 | ||||||
F-38
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(In
Thousands)
|
||||||||||||
|
Capital
expenditures
|
||||||||||||
|
Fluids
Division
|
$ | 84,134 | $ | 76,531 | $ | 18,877 | ||||||
|
Offshore
Division
|
||||||||||||
|
Offshore
Services
|
17,930 | 14,299 | 29,732 | |||||||||
|
Maritech
|
26,832 | 84,970 | 178,392 | |||||||||
|
Intersegment
eliminations
|
(454 | ) | (247 | ) | (5,113 | ) | ||||||
|
Total
Offshore Division
|
44,308 | 99,022 | 203,011 | |||||||||
|
Production
Enhancement Division
|
||||||||||||
|
Production
Testing
|
9,036 | 25,904 | 22,513 | |||||||||
|
Compressco
|
2,944 | 33,241 | 23,676 | |||||||||
|
Total
Production Enhancement Division
|
11,980 | 59,145 | 46,189 | |||||||||
|
Corporate
overhead
|
11,351 | 27,401 | 7,997 | |||||||||
|
Consolidated
|
$ | 151,773 | $ | 262,099 | $ | 276,074 | ||||||
(1)
Amounts
reflected include the following general corporate expenses:
|
2009
|
2008
|
2007
|
||||||||||
|
General and
administrative expense
|
$ | 40,173 | $ | 34,185 | $ | 31,533 | ||||||
|
Depreciation
and amortization
|
3,011 | 2,459 | 1,500 | |||||||||
|
Interest
expense
|
13,064 | 17,210 | 17,574 | |||||||||
|
Other general
corporate (income) expense, net
|
1,479 | (8,246 | ) | 336 | ||||||||
|
Total
|
$ | 57,727 | $ | 45,608 | $ | 50,943 | ||||||
(2)
Includes
assets of discontinued operations.
Summarized
financial information concerning the geographic areas of our customers and in
which we operate at December 31, 2009, 2008, and 2007 is presented
below:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(In
Thousands)
|
||||||||||||
|
Revenues from
external customers:
|
||||||||||||
|
U.S.
|
$ | 751,101 | $ | 855,380 | $ | 850,857 | ||||||
|
Canada
and Mexico
|
37,984 | 36,939 | 25,330 | |||||||||
|
South
America
|
17,372 | 15,522 | 9,307 | |||||||||
|
Europe
|
68,015 | 85,713 | 80,495 | |||||||||
|
Africa
|
2,477 | 1,973 | 2,498 | |||||||||
|
Asia
and other
|
1,928 | 13,538 | 13,996 | |||||||||
|
Total
|
$ | 878,877 | $ | 1,009,065 | $ | 982,483 | ||||||
|
Transfers
between geographic areas:
|
||||||||||||
|
U.S.
|
$ | - | $ | 2,578 | $ | 318 | ||||||
|
Canada
and Mexico
|
- | - | - | |||||||||
|
South
America
|
- | 225 | - | |||||||||
|
Europe
|
1,472 | 55 | 1,548 | |||||||||
|
Africa
|
- | - | - | |||||||||
|
Asia
and other
|
- | - | - | |||||||||
|
Eliminations
|
(1,472 | ) | (2,858 | ) | (1,866 | ) | ||||||
|
Total
revenues
|
$ | 878,877 | $ | 1,009,065 | $ | 982,483 | ||||||
|
Identifiable
assets:
|
||||||||||||
|
U.S.
|
$ | 1,197,512 | $ | 1,273,642 | $ | 1,163,604 | ||||||
|
Canada
and Mexico
|
32,811 | 26,732 | 22,482 | |||||||||
|
South
America
|
41,556 | 27,379 | 17,843 | |||||||||
|
Europe
|
59,633 | 70,964 | 79,972 | |||||||||
|
Africa
|
5,468 | 4,684 | 1,821 | |||||||||
|
Asia
and other
|
10,649 | 9,636 | 5,772 | |||||||||
|
Eliminations
and discontinued operations
|
(30 | ) | (413 | ) | 4,042 | |||||||
|
Total
identifiable assets
|
$ | 1,347,599 | $ | 1,412,624 | $ | 1,295,536 | ||||||
F-39
In
2008 and 2007, a single purchaser of Maritech’s oil and gas production, Shell
Trading (US) Company, accounted for approximately 13.5% and 12.5%, respectively,
of our consolidated revenues. In 2009, no single customer accounted for more
than 10% of our consolidated revenues.
NOTE
R — SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)
As part of the Offshore Division activities,
Maritech and its subsidiaries periodically acquire oil and gas reserves and
operate the properties in exchange for assuming the proportionate share of the
well abandonment and decommissioning obligations associated with such
properties. Accordingly, our Maritech segment is included within our Offshore
Division.
Costs
Incurred in Property Acquisition, Exploration, and Development
Activities
The following table reflects the costs incurred
in oil and gas property acquisition, exploration, and development activities
during the years indicated. Consideration given for the acquisition of proved
properties includes the assumption, and any subsequent revision, of the amount
of the proportionate share of the well abandonment and decommissioning
obligations associated with the properties.
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(In
Thousands)
|
||||||||||||
|
Acquisition
|
$ | 2,993 | $ | 45,373 | $ | 82,976 | ||||||
|
Exploration
|
6,820 | 8,522 | - | |||||||||
|
Development
|
38,806 | 79,620 | 152,372 | |||||||||
|
Total
costs incurred
|
$ | 48,619 | $ | 133,515 | $ | 235,348 | ||||||
Approximately $5.0 million of the exploration
costs incurred during 2009 was capitalized as of December 31, 2009, pending the
determination of proved reserves. These capitalized exploration costs are
associated with the drilling of a single well, which is expected to be evaluated
in March 2010.
Capitalized
Costs Related to Oil and Gas Producing Activities:
Aggregate amounts
of capitalized costs relating to our oil and gas producing activities and the
aggregate amounts of related accumulated depletion, depreciation, and
amortization as of the dates indicated, are presented below.
|
December
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(In
Thousands)
|
||||||||
|
Undeveloped
properties
|
$ | 16,592 | $ | 15,284 | ||||
|
Proved
developed properties being amortized
|
668,512 | 691,398 | ||||||
|
Total
capitalized costs
|
685,104 | 706,682 | ||||||
|
Less
accumulated depletion, depreciation,
|
||||||||
|
and
amortization
|
(388,069 | ) | (367,952 | ) | ||||
|
Net
capitalized costs
|
$ | 297,035 | $ | 338,730 | ||||
Capitalized costs
include the costs of support equipment and facilities. Also included in
capitalized costs of proved developed properties being amortized is our estimate
of our proportionate share of well abandonment and decommissioning liabilities
assumed relating to these properties, which is also reflected as decommissioning
and other asset retirement obligations in the accompanying consolidated balance
sheets.
F-40
Results
of Operations for Oil and Gas Producing Activities:
Results of
operations for oil and gas producing activities excludes general and
administrative
and interest
expenses directly related to such activities as well as any allocation of
corporate or divisional overhead.
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(In
Thousands)
|
||||||||||||
|
Oil and gas
sales revenues
|
$ | 174,191 | $ | 207,180 | $ | 213,338 | ||||||
|
Production
(lifting) costs
(1)
|
79,115 | 89,574 | 89,605 | |||||||||
|
Depreciation,
depletion, and amortization
|
79,610 | 82,971 | 73,835 | |||||||||
|
Impairments
of properties
(2)
|
11,410 | 42,658 | 76,094 | |||||||||
|
Excess
decommissioning and abandonment costs
|
23,771 | 7,045 | 12,153 | |||||||||
|
Exploration
expenses
|
151 | 224 | 1,174 | |||||||||
|
Accretion
expense
|
7,717 | 7,631 | 6,841 | |||||||||
|
Dry hole
costs
|
- | 9,063 | 1,699 | |||||||||
|
Gain on
insurance recoveries
|
(45,391 | ) | (697 | ) | (3,245 | ) | ||||||
|
Pretax
income (loss) from producing activities
|
17,808 | (31,289 | ) | (44,818 | ) | |||||||
|
Income tax
expense (benefit)
|
6,551 | (8,455 | ) | (16,549 | ) | |||||||
|
Results
of oil and gas producing activities
|
$ | 11,257 | $ | (22,834 | ) | $ | (28,269 | ) | ||||
|
(1)
|
Production
costs during 2009, 2008, and 2007 include certain hurricane repair
expenses of $8.2 million, $8.5 million, and $13.5 million,
respectively.
|
|
(2)
|
Impairments of
oil and gas properties during 2007 were primarily due to the increase in
Maritech’s decommissioning liability as a result of contested insurance
coverage. Impairments of oil and gas properties during 2008 were primarily
due to decreased oil and natural gas
prices.
|
Estimated
Quantities of Proved Oil and Gas Reserves (Unaudited):
Proved oil and gas
reserves are defined as the estimated quantities of crude oil, natural gas, and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions. Reservoirs are considered
proved if economic productibility is supported by either actual production or
conclusive formation tests. The area of a reservoir considered proved includes
(a) that portion delineated by drilling and defined by gas-oil and/or gas-water
contacts, if any, and (b) the immediately adjoining portions not yet drilled,
but which can be reasonably judged as economically productive on the basis of
available geological and engineering data. Reserves which can be produced
economically through the application of improved recovery techniques are
included in the “proved” classification when successful testing by a pilot
project, or the operation of an installed program in the reservoir, provides
support for the engineering analysis on which the project or program was
based.
The reliability of
reserve information is considerably affected by several factors. Reserve
information is imprecise due to the inherent uncertainties in, and the limited
nature of, the database upon which the estimating of reserve information is
predicated. Moreover, the methods and data used in estimating reserve
information are often necessarily indirect or analogical in character, rather
than direct or deductive. Furthermore, estimating reserve information, by
applying generally accepted petroleum engineering and evaluation principles,
involves numerous judgments based upon the engineer’s educational background,
professional training, and professional experience. The extent and significance
of the judgments to be made are, in themselves, sufficient to render reserve
information inherently imprecise.
Through our
Maritech subsidiary, we employ full-time, experienced reservoir engineers and
geologists, who are responsible for determining proved reserves in conformance
with guidelines established by the SEC. These SEC guidelines were revised
effective with the December 31, 2009 information. The impact of the revision to
these reserve guidelines was not considered significant to our proved oil and
gas reserve volumes. The value of the oil and gas reserves was affected by the
impact of the new average pricing requirements. Reserve estimates were prepared
by Maritech engineers based upon their interpretation of production performance
data and geologic interpretation of sub-surface information derived from the
drilling of wells. In accordance with Maritech’s documented oil and gas reserve
policy as prescribed by our Board of
F-41
Directors, the
preparation of these reserve estimates is subject to Maritech’s system of
internal control whereby key inputs in preparing reserve estimates, such as oil
and natural gas pricing data, oil and gas property ownership interest
percentages, and data regarding levels of operating, development, and
abandonment costs, are reviewed by Maritech personnel outside of the reserve
engineering department. Reserve estimates are also reviewed by Maritech’s
President, who is also a licensed professional engineer and has overall
responsibility for overseeing the preparation of the proved reserve estimates.
In addition to the complete analysis and review by Maritech’s internal reservoir
engineers, independent petroleum engineers and geologists performed reserve
audits of approximately 80.2% of our proved reserve volumes as of December 31,
2009. The use of the term “reserve audit” is intended only to refer to the
collective application of the engineering and geologic procedures which the
independent petroleum engineering firms were engaged to perform and may be
defined and used differently by other companies.
A
reserve audit is the process of reviewing certain of the pertinent facts
interpreted and assumptions made that have resulted in an estimate of reserves
prepared by others and the rendering of an opinion about the appropriateness of
the methodologies employed, the adequacy and quality of the data relied upon,
the depth and thoroughness of the reserves estimation process, the
classification of reserves appropriate to the relevant definitions used, and the
reasonableness of the estimated reserve quantities. In performing a reserve
audit, an independent petroleum engineering firm meets with our technical staff
to collect all necessary geologic, geophysical, engineering, and economic data,
and performs an independent reserve evaluation. The reserve audit of our oil and
gas reserves involves the rigorous examination of our technical evaluation, as
well as the interpretation and extrapolation of well information such as flow
rates, reservoir pressure declines, and other technical information and
measurements. Maritech’s internal reservoir engineers interpret this data to
determine the nature of the reservoir and, ultimately, the quantity of proved
oil and gas reserves attributable to the specific property. Our proved reserves,
as reflected in this Annual Report, include only quantities that Maritech
expects to recover commercially using current technology, prices, and costs, and
within existing economic conditions, operating methods, and governmental
regulations. While Maritech can be reasonably certain that the proved reserves
are economically producible, the timing and ultimate recovery can be affected by
a number of factors, including completion of development projects, reservoir
performance, regulatory approvals, and changes in projections of long-term oil
and gas prices. Revisions can include upward or downward changes in the
previously estimated volumes of proved reserves for existing fields due to
evaluation of (1) already available geologic, reservoir, or production data or
(2) new geologic or reservoir data obtained from wells. Revisions can also occur
associated with significant changes in development strategy, oil and gas prices,
or the related production equipment/facility capacity. Maritech’s independent
petroleum engineers also examined the reserve estimates with respect to reserve
categorization, using the definitions for proved reserves set forth in
Regulation S-X Rule 4-10(a), Staff Accounting Bulletin No. 113, and
subsequent SEC staff interpretations and guidance.
Maritech engaged
Ryder Scott Company, L.P. and DeGolyer and MacNaughton to perform the
engineering audits of a portion of our oil and gas reserves as of December 31,
2009, 2008, and 2007. Both Ryder Scott Company, L.P. and DeGolyer and
MacNaughton are established oil and gas reservoir engineering firms providing
engineering services worldwide. The staffs of both of these firms, including the
personnel assigned to the reserve audits of Maritech’s reserve estimates,
include licensed reservoir engineers experienced in performing these services.
In the conduct of these reserve audits, these independent petroleum engineering
firms did not independently verify the accuracy and completeness of information
and data furnished by Maritech with respect to property interests owned, oil and
gas production and well tests from examined wells, or historical costs of
operation and development; however, they did verify product prices, geological
structural and isopach maps, and reservoir data such as well logs, core
analyses, and pressure measurements. If, in the course of the examinations, a
matter of question arose regarding the validity or sufficiency of any such
information or data, the independent petroleum engineering firms did not accept
such information or data until all questions relating thereto were
satisfactorily resolved. Furthermore, in instances where decline curve analysis
was not adequate in determining proved producing reserves, the independent
petroleum engineering firms performed volumetric analysis, which included the
analysis of geologic, reservoir, and fluids data. Proved undeveloped reserves
were analyzed by volumetric analysis, which takes into consideration recovery
factors relative to the geology of the location and similar reservoirs. Where
applicable, the independent petroleum engineering firms examined data related to
well spacing, including potential drainage from offsetting producing wells, in
evaluating proved reserves of undrilled well locations.
F-42
The reserve audit
performed by Ryder Scott Company, L.P. included certain properties selected by
Maritech, including all of our most significant properties, excluding the
Cimarex Properties, and represented approximately 64.0% of our total proved oil
and gas reserve volumes (66.8% of discounted future net pretax cash flows) as of
December 31, 2009. The reserve audit performed by DeGolyer and MacNaughton
included the Cimarex Properties acquired in December 2007 and represented
approximately 16.2% of our total proved oil and gas reserve volumes (15.1% of
discounted future net pretax cash flows) as of December 31, 2009. The
independent petroleum engineers represent in their audit reports that they
believe Maritech’s estimates of future reserves were prepared in accordance with
generally accepted petroleum engineering and evaluation principles for the
estimation of future reserves in accordance with SEC standards. In each case,
the independent petroleum engineers concluded that the overall proved reserves
for the reviewed properties as estimated by Maritech were, in the aggregate,
reasonable within the established audit tolerance guidelines of 10% as set forth
in the Standards Pertaining to the Estimating and Auditing of Oil and Gas
Reserves Information promulgated by the SPE. There were no limitations imposed
or encountered by Maritech or the independent petroleum engineers in the
preparation of our estimated reserves or in the performance of the reserve
audits by the independent petroleum engineers.
The following
information is presented with regard to our proved oil and gas reserve
quantities reported in accordance with guidelines established by the SEC, and
these guidelines were revised effective with the December 31, 2009 information.
The impact of the revision to these reserve guidelines was not considered
significant to our proved oil and gas reserve volumes. The reserve values and
cash flow amounts reflected in the following reserve disclosures as of December
31, 2009 are based on the average price of oil and natural gas during the twelve
month period then ended, determined as an unweighted arithmetic average of the
first-day-of-the-month for each month within the period. The reserve values and
cash flow amounts for periods prior to December 31, 2009 are based on prices as
of each yearend. All of Maritech’s reserves are located in U. S. state and
federal offshore waters of the Gulf of Mexico and onshore
Louisiana.
|
Reserve
Quantity Information
|
Oil
|
Gas
|
||
|
(MBbls)
|
(MMcf)
|
|||
|
December 31,
2006
|
||||
|
Proved
developed reserves
|
7,872
|
36,373
|
||
|
Proved
undeveloped reserves
|
957
|
3,365
|
||
|
Total proved
reserves at December 31, 2006
|
8,829
|
39,738
|
||
|
December 31,
2007
|
||||
|
Proved
developed reserves
|
6,646
|
43,898
|
||
|
Proved
undeveloped reserves
|
89
|
2,909
|
||
|
Total proved
reserves at December 31, 2007
|
6,735
|
46,807
|
||
|
December 31,
2008
|
||||
|
Proved
developed reserves
|
4,504
|
40,988
|
||
|
Proved
undeveloped reserves
|
1,433
|
1,024
|
||
|
Total proved
reserves at December 31, 2008
|
5,937
|
42,012
|
||
|
December 31,
2009
|
||||
|
Proved
developed reserves
|
5,690
|
32,387
|
||
|
Proved
undeveloped reserves
|
1,383
|
1,124
|
||
|
Total proved
reserves at December 31, 2009
|
7,073
|
33,511
|
||
F-43
|
Oil
|
Gas
|
|||||||
|
(MBbls)
|
(MMcf)
|
|||||||
|
Total proved
reserves at December 31, 2006
|
8,829 | 39,738 | ||||||
|
Revisions of
previous estimates
|
(760 | ) | (6,280 | ) | ||||
|
Production
|
(1,985 | ) | (9,515 | ) | ||||
|
Extensions
and discoveries
|
584 | 2,766 | ||||||
|
Purchases of
reserves in place
|
174 | 20,621 | ||||||
|
Sales of
reserves in place
|
(107 | ) | (523 | ) | ||||
|
Total proved
reserves at December 31, 2007
|
6,735 | 46,807 | ||||||
|
Revisions of
previous estimates
|
(40 | ) | (1,774 | ) | ||||
|
Production
|
(1,467 | ) | (10,989 | ) | ||||
|
Extensions
and discoveries
|
521 | 2,771 | ||||||
|
Purchases of
reserves in place
|
191 | 5,199 | ||||||
|
Sales of
reserves in place
|
(3 | ) | (2 | ) | ||||
|
Total proved
reserves at December 31, 2008
|
5,937 | 42,012 | ||||||
|
Revisions of
previous estimates
|
1,971 | (623 | ) | |||||
|
Production
|
(1,325 | ) | (10,449 | ) | ||||
|
Extensions
and discoveries
|
569 | 3,365 | ||||||
|
Purchases of
reserves in place
|
- | - | ||||||
|
Sales of
reserves in place
|
(79 | ) | (794 | ) | ||||
|
Total proved
reserves at December 31, 2009
|
7,073 | 33,511 | ||||||
Standardized
Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas
Reserves:
“Standardized measure” relates to the
estimated discounted future net cash flows and major components of that
calculation relating to proved reserves at the end of the year in the aggregate,
based on SEC prescribed prices and costs, using statutory tax rates and using a
10% annual discount rate. The standardized measure is not an estimate of the
fair value of proved oil and gas reserves. Probable and possible reserves, which
may become proved in the future, are excluded from these calculations.
Furthermore, prices used to determine the standardized measure are prior to the
impact of hedge derivatives and are influenced by seasonal demand and other
factors and may not be representative in estimating future revenues or reserve
data.
The standardized
measure of discounted future net cash flows relating to proved oil and gas
reserves attributed to our oil and gas properties is as follows:
|
December
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(In
Thousands)
|
||||||||
|
Future cash
inflows
|
$ | 536,594 | $ | 494,908 | ||||
|
Future
costs
|
||||||||
|
Production
|
192,152 | 192,998 | ||||||
|
Development
and abandonment
|
235,042 | 251,015 | ||||||
|
Future net
cash flows before income taxes
|
109,400 | 50,895 | ||||||
|
Future income
taxes
|
(14,846 | ) | (2,399 | ) | ||||
|
Future net
cash flows
|
94,554 | 48,496 | ||||||
|
Discount at
10% annual rate
|
(8,505 | ) | 11,852 | |||||
|
Standardized
measure of discounted future net cash flows
|
$ | 86,049 | $ | 60,348 | ||||
F-44
Changes
in Standardized Measure of Discounted Future Net Cash Flows:
|
Year
Ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(In
Thousands)
|
||||||||||||
|
Standardized
measure, beginning of year
|
$ | 60,348 | $ | 298,679 | $ | 186,090 | ||||||
|
Sales,
net of production costs
|
(95,076 | ) | (110,561 | ) | (111,580 | ) | ||||||
|
Net
change in prices, net of production costs
|
43,098 | (297,719 | ) | 179,079 | ||||||||
|
Changes
in future development costs
|
2,235 | (30,590 | ) | 10,635 | ||||||||
|
Development
costs incurred
|
10,585 | 39,035 | 26,615 | |||||||||
|
Accretion
of discount
|
6,396 | 41,245 | 27,569 | |||||||||
|
Net
change in income taxes
|
(7,536 | ) | 110,150 | (24,171 | ) | |||||||
|
Purchases
of reserves in place
|
- | 13,233 | 55,673 | |||||||||
|
Extensions
and discoveries
|
27,873 | 19,108 | 53,504 | |||||||||
|
Sales
of reserves in place
|
1,268 | (252 | ) | 4,114 | ||||||||
|
Net
change due to revision in quantity estimates
|
41,045 | (6,295 | ) | (83,826 | ) | |||||||
|
Changes
in production rates (timing) and other
|
(4,187 | ) | (15,685 | ) | (25,023 | ) | ||||||
|
Subtotal
|
25,701 | (238,331 | ) | 112,589 | ||||||||
|
Standardized
measure, end of year
|
$ | 86,049 | $ | 60,348 | $ | 298,679 | ||||||
NOTE
S — QUARTERLY FINANCIAL INFORMATION (Unaudited)
Summarized
quarterly financial data for 2009 and 2008 is as follows:
|
Three
Months Ended 2009
|
||||||||||||||||
|
March
31
|
June
30
|
September
30
|
December
31
|
|||||||||||||
|
(In
Thousands, Except Per Share Amounts)
|
||||||||||||||||
|
Total
revenues
|
$ | 195,251 | $ | 217,944 | $ | 253,975 | $ | 211,707 | ||||||||
|
Gross
profit
|
43,370 | 40,389 | 62,773 | 66,565 | ||||||||||||
|
Income before
discontinued operations
|
11,370 | 9,210 | 22,812 | 25,415 | ||||||||||||
|
Net
income
|
11,162 | 9,175 | 22,662 | 25,805 | ||||||||||||
|
Net income
per share before discontinued
|
||||||||||||||||
|
operations
|
$ | 0.15 | $ | 0.12 | $ | 0.30 | $ | 0.34 | ||||||||
|
Net income
per diluted share before
|
||||||||||||||||
|
discontinued
operations
|
$ | 0.15 | $ | 0.12 | $ | 0.30 | $ | 0.33 | ||||||||
|
Three
Months Ended 2008
|
||||||||||||||||
|
March
31
|
June
30
|
September
30
|
December
31
|
|||||||||||||
|
(In
Thousands, Except Per Share Amounts)
|
||||||||||||||||
|
Total
revenues
|
$ | 225,156 | $ | 304,389 | $ | 249,099 | $ | 230,421 | ||||||||
|
Gross profit
(loss)
|
42,047 | 77,427 | 43,708 | (11,181 | ) | |||||||||||
|
Income (loss)
before discontinued operations
|
7,354 | 30,157 | 12,118 | (59,284 | ) | |||||||||||
|
Net income
(loss)
|
6,687 | 29,417 | 11,657 | (59,897 | ) | |||||||||||
|
Net income
(loss) per share before
|
||||||||||||||||
|
discontinued
operations
|
$ | 0.10 | $ | 0.41 | $ | 0.16 | $ | (0.79 | ) | |||||||
|
Net income
(loss) per diluted share before
|
||||||||||||||||
|
discontinued
operations
|
$ | 0.10 | $ | 0.40 | $ | 0.16 | $ | (0.79 | ) | |||||||
F-45
NOTE
T — STOCKHOLDERS’ RIGHTS PLAN
On
October 27, 1998, the Board of Directors adopted a stockholders’ rights plan
(the Rights Plan) designed to assure that all of our stockholders receive fair
and equal treatment in the event of a proposed takeover. The Rights Plan helps
to guard against partial tender offers, open market accumulations and other
abusive tactics to gain control of our company without paying an adequate and
fair price in any takeover attempt. The Rights are not presently exercisable and
are not represented by separate certificates. We are currently not aware of any
effort of any kind to acquire control of our company.
The terms of the
Rights Plan, as adopted in 1998, provide that each holder of record of an
outstanding share of common stock subsequent to November 6, 1998, receives a
dividend distribution of one Preferred Stock Purchase Right. The Rights Plan
would be triggered if an acquiring party accumulates or initiates a tender offer
to purchase 20% or more of our common stock and would entitle holders of the
Rights to purchase either our stock or shares in an acquiring entity at half of
market value. Each Right entitles the holder thereof to purchase 1/100 of a
share of Series One Junior Participating Preferred Stock for $50.00 per share,
subject to adjustment. We would generally be entitled to redeem the Rights at
$.01 per Right at any time until the tenth day following the time the Rights
become exercisable.
On
November 6, 2008, the Board of Directors entered into a First Amendment to the
Rights Agreement. The amendment extends the term of the Rights Agreement and the
final expiration date of our rights thereunder, which would otherwise have
expired at the close of business on November 6, 2008, until the close of
business on November 6, 2018. The amendment also increases the purchase price
for each 1/100 of a share of Series One Junior Participating Preferred Stock
from $50.00 per share to $100.00 per share.
F-46
TABLE OF CONTENTS
Part IItem 1. BusinessItem 1A. Risk FactorsItem 1B. Unresolved Staff CommentsItem 2. PropertiesItem 3. Legal ProceedingsItem 4. [removed and Reserved.]Part IIItem 5. Market For Registrant S Common Equity, Related Stockholder Matters and Issuer Repurchases Of Equity SecuritiesItem 6. Selected Financial DataItem 7. Management S Discussion and Analysis Of Financial Condition and Results Of OperationItem 7A. Quantitative and Qualitative Disclosures About Market RiskItem 8. Financial Statements and Supplementary DataItem 9. Changes in and Disagreements with Accountants on Accounting and Financial DisclosureItem 9A. Controls and ProceduresItem 9B. Other InformationPart IIIItem 10. Directors, Executive Officers, and Corporate GovernanceItem 11. Executive CompensationItem 12. Security Ownership Of Certain Beneficial Owners and Management and Related Stockholder MattersItem 13. Certain Relationships and Related Transactions, and Director IndependenceItem 14. Principal Accounting Fees and ServicesPart IVItem 15. Exhibits and Financial Statement Schedules