e10vk
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
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Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the fiscal year ended December 31, 2006
or
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Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the Transition Period from to
Commission File No. 0-20310
SUPERIOR ENERGY SERVICES, INC.
(Exact name of registrant as specified in its charter)
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Delaware
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75-2379388 |
(State or other jurisdiction of incorporation or organization)
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(I.R.S. Employer Identification No.) |
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1105 Peters Road |
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Harvey, LA
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70058 |
(Address of principal executive offices)
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(Zip Code) |
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Registrants telephone number:
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(504) 362-4321 |
Securities registered pursuant to Section 12(b) of the Act:
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Title of each class:
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Name of each exchange on which registered:
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Common Stock, $.001 Par Value
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New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule
405 of the Securities Act. Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or
15(d) of the Act. Yes o No þ
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 þ No o
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 registrants 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. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer,
or a non-accelerated filer. See definition of accelerated filer and large accelerated filer in
Rule 12b-2 of the Exchange Act.
Large accelerated filer þ Accelerated filer o Non-accelerated o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes o No þ
The aggregate market value of the voting stock held by non-affiliates of the registrant at June 30,
2006 based on the closing price on the New York Stock Exchange on that date was $2,726,758,000.
The number of shares of the registrants common stock outstanding on February 16, 2007 was
80,636,962.
DOCUMENTS INCORPORATED BY REFERENCE
Certain information called for by Items 10, 11, 12, 13 and 14 of Part III is incorporated by
reference from the registrants definitive proxy statement to be filed pursuant to Regulation 14A.
SUPERIOR ENERGY SERVICES, INC.
Annual Report on Form 10-K for
the Fiscal Year Ended December 31, 2006
TABLE OF CONTENTS
(i)
FORWARD-LOOKING STATEMENTS
We have included or incorporated by reference in this Annual Report on Form 10-K, and from time to
time our management may make, statements that may constitute forward-looking statements within
the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995.
Forward-looking statements are not historical facts but instead represent only our current belief
regarding future events, many of which, by their nature, are inherently uncertain and outside our
control. The forward-looking statements contained in this Annual Report are based on information
as of the date of this Annual Report. Many of these forward looking statements relate to future
industry trends, actions, future performance or results of current and anticipated initiatives and
the outcome of contingencies and other uncertainties that may have a significant impact on our
business, future operating results and liquidity. We try, whenever possible, to identify these
statements by using words such as anticipate, believe, should, estimate, expect, plan,
project and similar expressions. We caution you that these statements are only predictions and
are not guarantees of future performance. These forward-looking statements and our actual results,
developments and business are subject to certain risks and uncertainties that could cause actual
results and events to differ materially from those anticipated by these statements. By identifying
these statements for you in this manner, we are alerting you to the possibility that our actual
results may differ, possibly materially, from the anticipated results indicated in these
forward-looking statements. Important factors that could cause actual results to differ from those
in the forward-looking statements include, among others, those discussed below and under Risk
Factors in Part I, Item 1A and Managements Discussion and Analysis of Financial Condition and
Results of Operations in Part II, Item 7.
PART I
Item 1. Business
General
We are a leading, highly diversified provider of specialized oilfield services and equipment. We
focus on serving the drilling-related needs of oil and gas companies primarily through our rental
tools segment, and the production-related needs of oil and gas companies through our well
intervention, rental tools and marine segments. We believe that we are one of the few companies
capable of providing the services, tools and liftboats necessary to maintain, enhance and extend
the life of offshore producing wells, as well as plug and abandonment services at the end of their
life cycle. We also own and operate mature oil and gas properties in the Gulf of Mexico. We
believe that our ability to provide our customers with multiple services and to coordinate and
integrate their delivery allows us to maximize efficiency, reduce lead-time and provide
cost-effective solutions for our customers. We have expanded geographically so that we now have a
significant presence in both select domestic land and international markets.
Operations
Our operations are organized into the following four business segments:
Well Intervention Services. We provide well intervention services that stimulate oil and
gas production. Our well intervention services include coiled tubing, electric line, pumping and
stimulation, gas lift, well control, snubbing, recompletion, engineering and well evaluation
services, platform and field management, offshore oil and gas cleaning, decommissioning, plug and
abandonment and mechanical wireline. We believe we are the leading provider of mechanical wireline
services in the Gulf of Mexico with approximately 210 offshore wireline units, 90 land wireline
units and 10 dedicated liftboats configured specifically for wireline services. We also believe we
are a leading provider of rigless plug and abandonment services in the Gulf of Mexico. We recently
completed construction of an 880-ton derrick barge which was deployed off the coast of Malaysia
under a charter that is scheduled to run through October 2007. We also manufacture and sell
specialized drilling rig instrumentation equipment.
In December 2006, we significantly expanded the domestic land presence of our well intervention
segment when we acquired Warrior Energy Services Corporation (Warrior), a provider of
production-related services. Warrior has 82 electric line units, 15 rig-assist snubbing units and
six coiled tubing units and provides services onshore in
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Alabama, Arkansas, Colorado, Kansas, Louisiana, Mississippi, Montana, New Mexico, North Dakota,
Oklahoma, Texas, Utah and Wyoming, and offshore in the Gulf of Mexico.
Rental Tools. We are a leading provider of rental tools. We manufacture, sell and rent
specialized equipment for use with offshore and onshore oil and gas well drilling, completion,
production and workover activities. Through internal growth and acquisitions, we have increased
the size and breadth of our rental tool inventory and geographic scope of operations so that we now
conduct operations offshore in the Gulf of Mexico, onshore in the United States and in select
international market areas. We currently have locations in all of the major staging points in
Louisiana and Texas for offshore oil and gas activities in the Gulf of Mexico and in North
Louisiana, Arkansas, Oklahoma and Wyoming. Our rental tools segment also conducts operations in
Venezuela, Trinidad, Mexico, Colombia, Eastern Canada, the United Kingdom, Continental Europe, the
Middle East, West Africa and the Asia Pacific region. Our rental tools include pressure control
equipment, specialty tubular goods including drill pipe and landing strings, connecting iron,
handling tools, bolting equipment, stabilizers, drill collars and on-site accommodations.
Marine Services. We own and operate a fleet of liftboats that we believe is highly
complementary to our well intervention services. A liftboat is a self-propelled, self-elevating
work platform with legs, cranes and living accommodations. Our fleet consists of 37 liftboats,
including 10 liftboats configured specifically for wireline services (included in our well
intervention segment) and 27 in our rental fleet with leg-lengths ranging from 145 feet to 250
feet. Our liftboat fleet has leg-lengths and deck spaces that are suited to deliver our
production-related bundled services and support customers in their construction, maintenance and
other production-enhancement projects. All of our liftboats are currently located in the Gulf of
Mexico, but we may reposition some of our larger liftboats to international market areas if
opportunities arise.
Oil and Gas Operations. Through our subsidiary, SPN Resources, LLC (SPN Resources), we
acquire mature oil and gas properties in the Gulf of Mexico to provide our customers a
cost-effective alternative to the plugging, abandoning and decommissioning process. Owning oil and
gas properties provides additional opportunities for our well intervention, decommissioning and
platform management services, particularly during periods when demand from our traditional
customers is weak due to cyclical or seasonal factors. Once properties are acquired, we utilize
our production-related assets and services to maintain, enhance and extend existing production of
these properties. At the end of a propertys economic life, we plug and abandon the wells and
decommission and abandon the facilities. As of December 31, 2006, we had interests in 31 offshore
blocks containing 65 structures and approximately 156 producing wells. As of December 31, 2006, we
had reserves of approximately 13.9 million barrels of oil equivalent (mmboe) with a PV-10 of $230.6
million and approximately 83% of our reserves were classified as proved developed.
For additional industry segment financial information, see note 15 to our consolidated financial
statements included in Item 8 of this Form 10-K.
Customers
Our customers have primarily been the major and independent oil and gas companies. Sales to Shell
accounted for approximately 12% and 10% of our total revenue in 2006 and 2005, respectively. In
2004, no customer accounted for more than 10% of revenue. We do not believe that the loss of any
one customer would have a material adverse effect on our revenues. However, our inability to
continue to perform services for a number of our large existing customers, if not offset by sales
to new or other existing customers could have a material adverse effect on our business and
operations.
Competition
We operate in highly competitive areas of the oilfield services industry. The products and
services of each of our principal operating segments are sold in highly competitive markets, and
our revenues and earnings can be affected by the following factors:
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changes in competitive prices; |
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oil and gas prices and industry perceptions of future prices; |
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fluctuations in the level of activity by oil and gas producers; |
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changes in the number of liftboats operating in the Gulf of Mexico; |
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the ability of oil and gas producers to generate capital; |
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general economic conditions; and |
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governmental regulation. |
We compete with the oil and gas industrys largest integrated oilfield service providers in the
production-related services provided by our well intervention segment. The rental tools divisions
of these companies, as well as several smaller companies that are single source providers of rental
tools, are our competitors in the rental tools market. In the marine services segment, we compete
with other companies that provide liftboat services in the Gulf of Mexico. We also compete with
other companies for the acquisition of mature oil and gas properties in the Gulf of Mexico. We
believe that the principal competitive factors in the market areas that we serve are price, product
and service quality, safety record, equipment availability and technical proficiency.
Our operations may be adversely affected if our current competitors or new market entrants
introduce new products or services with better features, performance, prices or other
characteristics than our products and services, or if they would offer to pay more for mature oil
and gas properties. Further, if our competitors construct additional liftboats for the Gulf of
Mexico market area, it could affect vessel utilization and resulting day rates. Competitive
pressures or other factors also may result in significant price competition that could reduce our
operating cash flow and earnings. In addition, competition among oilfield service and equipment
providers is affected by each providers reputation for safety and quality. Although we believe
that our reputation for safety and quality service is good, we cannot assure that we will be able
to maintain our competitive position.
Health, Safety and Environmental Assurance
We have established health, safety and environmental performance as a corporate priority. Our goal
is to be an industry leader in this area by focusing on the belief that all safety and
environmental incidents are preventable and an injury-free workplace is achievable by emphasizing
correct behavior. We have a company-wide effort to enhance our behavioral safety process and
training program and make safety a constant focus of awareness through open communication with all
of our offshore and yard employees. In addition, we investigate all incidents with a priority of
identifying and implementing the corrective measures necessary to reduce the chance of
reoccurrence.
Potential Liabilities and Insurance
Our operations involve a high degree of operational risk, particularly of personal injury, damage
or loss of equipment and environmental accidents. Failure or loss of our equipment could result in
property damages, personal injury, environmental pollution and other damage for which we could be
liable. Litigation arising from the sinking of a liftboat or a catastrophic occurrence, such as a
fire, explosion or well blowout, at one of our offshore production facilities or a location where
our equipment and services are used may result in large claims for damages in the future. We
maintain insurance against risks that we believe is consistent in types and amounts with industry
standards and is required by our customers. Changes in the insurance industry in the past few
years have led to higher insurance costs and deductibles, as well as lower coverage limits causing
us to rely on self insurance against many risks associated with our business. The availability of
insurance covering risks we and our competitors typically insure against may continue to decrease
forcing us to self insure against more business risks, including the risks associated with
hurricanes, and the insurance that we are able to obtain may have higher deductibles, higher
premiums, lower limits and more restrictive policy terms.
Government Regulation
Our business is significantly affected by the following:
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Federal and state laws and other regulations relating to the oil and gas industry; |
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changes in such laws and regulations; and |
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the level of enforcement thereof. |
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We cannot predict the level of enforcement of existing laws and regulations or how such laws and
regulations may be interpreted by enforcement agencies or court rulings in the future. A decrease
in the level of industry compliance with or enforcement of these laws and regulations in the future
may adversely affect the demand for our services. We also cannot predict whether additional laws
and regulations will be adopted, or the effect such changes may have on us, our businesses or our
financial condition. The demand for our services from the oil and gas industry would be affected
by changes in applicable laws and regulations. The adoption of new laws and regulations curtailing
drilling for oil and gas in our operating areas for economic, environmental or other policy reasons
could also adversely affect our operations by limiting demand for our services.
Regulation of Oil and Gas Production
The oil and gas industry is subject to various types of regulation at federal and state levels.
This regulation includes requiring permits to drill wells, maintaining bonding requirements to
drill or operate wells, and regulating the location of wells, the method of drilling and casing
wells, stringent engineering and construction standards, and the plugging and abandoning of wells
and removal of production facilities. The oil and gas industry is also subject to various federal
and state conservation laws and regulations. These include regulations establishing maximum rates
of production from oil and natural gas wells, generally prohibiting the venting or flaring of
natural gas and imposing certain requirements regarding the ratability of production.
Virtually all of our oil and gas operations are located on federal oil and gas leases, which are
administered by the U.S. Department of Interior, Minerals Management Service, or MMS, pursuant to
the Outer Continental Shelf Lands Act, or OCSLA. These leases contain standardized terms that
require compliance with detailed MMS regulations and orders that are subject to interpretation and
change by MMS. Under some circumstances, MMS may require operations on federal leases to be
suspended or terminated.
To cover the various obligations of lessees on the Outer Continental Shelf, MMS generally requires
that lessees have substantial net worth or post bonds or other acceptable assurances that such
obligations will be met. The cost of these bonds or assurances can be substantial, and there is no
assurance that they can be obtained in all cases. We currently have bonded our offshore leases, as
required by MMS, consisting of a $3.0 million Area-Wide Bond plus a $300,000 Pipeline Right-of-Way
Bond. Currently, we are exempt from supplemental bonding.
MMS also administers the collection of royalties under the terms of the OCSLA and the oil and gas
leases issued under the act. The amount of royalties due is based upon the terms of the oil and
gas leases as well as the regulations promulgated by MMS. These regulations are amended from time
to time, and the amendments can affect the amount of royalties that we are obligated to pay to MMS.
However, we do not believe that these regulations or any future amendments will affect us in a way
that materially differs from the way it affects other oil and gas producers.
These regulations impact our customers needs for our services, as well as limit the amounts of oil
and natural gas we can produce from our wells. Because these statutes, rules and regulations
undergo constant review and often are amended, expanded and reinterpreted, we are unable to predict
the future cost or impact of regulatory compliance. The regulatory burden on the oil and gas
industry increases its cost of doing business and, consequently, affects our profitability.
Natural Gas Marketing, Gathering and Transportation
Historically, the transportation and sales of natural gas in interstate commerce have been
regulated pursuant to the various laws administered by the Federal Energy Regulatory Commission, or
FERC. Currently, the price for all first sales of natural gas is not regulated by FERC.
Accordingly, all of our natural gas sales may be made at market prices, subject to applicable
contract provisions. Sales of natural gas are affected by the availability, terms and cost of
pipeline transportation. FERC has also implemented regulations intended to make natural gas
transportation more accessible to gas buyers and sellers on an open-access, non-discriminatory
basis.
Certain of our pipeline systems are regulated for safety compliance by the U.S. Department of
Transportation, or DOT. Pursuant to the Pipeline Safety Improvement Act of 2002, DOT has
implemented regulations intended to increase pipeline operating safety. Among other provisions,
the regulations require that pipeline operators
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implement a pipeline integrity management program that must at a minimum include an inspection of
gas transmission pipeline facilities within the next ten years, and at least every seven years
thereafter.
We cannot predict what new or different regulations FERC, DOT and other regulatory agencies may
adopt, or what effect subsequent regulations may have on our activities. Similarly, it is
impossible to predict what proposals, if any, that affect the oil and natural gas industry might
actually be enacted by Congress or the various state legislatures and what effect, if any, such
proposals might have on us. Also, despite the recent trend toward federal deregulation of the
natural gas industry, we cannot predict whether or to what extent that trend will continue, or what
the ultimate effect will be on our sales of gas.
Federal Regulation of Petroleum
Our sales of oil and gas are not regulated and are at market prices. The price received from the
sale of these products is affected by the cost of transporting the products to market. Much of
that transportation is through interstate common carrier pipelines. FERC has implemented
regulations approving interstate transportation rates and establishing an indexing system for those
rates by which adjustments are made annually based on the rate of inflation, subject to certain
conditions and limitations. These regulations may tend to increase the cost of transporting oil
and natural gas by interstate pipeline, although the annual adjustments may result in decreased
rates in a given year.
Environmental Regulations
General. Our operations are subject to extensive federal, state and local laws and
regulations relating to the generation, storage, handling, emission, transportation and discharge
of materials into the environment. Permits are required for the conduct of our business and
operation of our various marine vessels and offshore production facilities. These permits can be
revoked, modified or renewed by issuing authorities. Governmental authorities enforce compliance
with their regulations through administrative or civil penalties, corrective action orders,
injunctions or criminal prosecution. Government regulations can increase the cost of planning,
designing, installing and operating our oil and gas properties. Although we believe that
compliance with environmental regulations will not have a material adverse effect on us, risks of
substantial costs and liabilities related to environmental compliance issues are part of oil and
gas production operations. No assurance can be given that significant costs and liabilities will
not be incurred. Also, it is possible that other developments, such as stricter environmental laws
and regulations, and claims for damages to property or persons resulting from oil and gas
production could result in substantial costs and liabilities to us.
Federal laws and regulations applicable to our operations include those controlling the discharge
of materials into the environment, requiring removal and cleanup of materials that may harm the
environment, requiring consistency with applicable coastal zone management plans, or otherwise
relating to the protection of the environment.
Our insurance policies provide liability coverage for sudden and accidental occurrences of
pollution or clean-up and containment in amounts that we believe are comparable to policy limits
carried by others in our industry.
Outer Continental Shelf Lands Act. OCSLA and regulations promulgated pursuant thereto
impose a variety of regulations relating to safety and environmental protection applicable to
lessees, permits and other parties operating on the Outer Continental Shelf. Specific design and
operational standards may apply to Outer Continental Shelf vessels, rigs, platforms, vehicles and
structures. Violations of lease conditions or regulations issued pursuant to OCSLA can result in
substantial civil and criminal penalties as well as potential court injunctions curtailing
operations and the cancellation of leases. Enforcement liabilities under OCSLA can result from
either governmental or citizen prosecution. We believe that we substantially comply with OCSLA and
its regulations.
Solid and Hazardous Waste. We currently lease numerous properties that have been used in
connection with the production of oil and gas for many years. Although we believe we utilized
operating and disposal practices that were standard in the industry at the time, it is possible
that hydrocarbons or other solid wastes may have been disposed of or released on or under the
properties currently leased by us. Federal and state laws applicable to oil and gas wastes and
properties continue to be stricter over time. Under these increasingly stringent requirements, we
could be required to remove or remediate previously disposed wastes (including wastes disposed or
released by prior
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owners and operators) or clean up property contamination (including groundwater contamination by
prior owners or operators) or to perform plugging operations to prevent future contamination. We
generate some hazardous wastes that are already subject to the Federal Resource Conservation and
Recovery Act, or RCRA, and comparable state statutes. The Environmental Protection Agency, or the
EPA, has limited the disposal options for certain hazardous wastes. It is possible that certain
wastes currently exempt from treatment as hazardous wastes may in the future be designated as
hazardous wastes under RCRA or other applicable statutes. We could, therefore, be subject to more
rigorous and costly disposal requirements in the future than we encounter today.
Superfund. The Comprehensive Environmental Response, Compensation, and Liability Act, or
CERCLA, also known as the Superfund law, imposes liability, without regard to fault or the
legality of the original conduct, on certain persons with respect to the release of hazardous
substances into the environment. These persons include the owner and operator of a site and any
party that disposed of or arranged for the disposal of hazardous substances found at a site.
CERCLA also authorizes the EPA, and in some cases, private parties, to undertake actions to clean
up such hazardous substances, or to recover the costs of such actions from the responsible parties.
In the course of business, we have generated and will continue to generate wastes that may fall
within CERCLAs definition of hazardous substances. We may also be an owner or operator of sites
on which hazardous substances have been released. As a result, we may be responsible under CERCLA
for all or part of the costs to clean up sites where such wastes have been disposed.
Oil Pollution Act. The federal Oil Pollution Act of 1990, or OPA, and resulting
regulations impose a variety of obligations on responsible parties related to the prevention of oil
spills and liability for damages resulting from such spills in waters of the United States. The
term waters of the United States has been broadly defined to include inland water bodies,
including wetlands and intermittent streams. OPA assigns liability to each responsible party for
oil removal costs and a variety of public and private damages. We believe that we substantially
comply with OPA and related federal regulations.
Clean Water Act. The Federal Water Pollution Control Act, or Clean Water Act, and
resulting regulations, which are implemented through a system of permits, also govern the discharge
of certain contaminants into waters of the United States. Sanctions for failure to comply strictly
with the Clean Water Act are generally resolved by payment of fines and correction of any
identified deficiencies. However, regulatory agencies could require us to cease operation of our
marine vessels or offshore production facilities that are the source of water discharges. We
believe that we substantially comply with the Clean Water Act and related federal and state
regulations.
Clean Air Act. Our operations are subject to local, state and federal laws and regulations
to control emissions from sources of air pollution. Payment of fines and correction of any
identified deficiencies generally resolve penalties for failure to comply strictly with air
regulations or permits. Regulatory agencies could also require us to cease operation of certain
marine vessels or offshore production facilities that are air emission sources. We believe that we
substantially comply with the emission standards under local, state, and federal laws and
regulations.
Maritime Employees
Certain of our employees who perform services on offshore platforms and liftboats are covered by
the provisions of the Jones Act, the Death on the High Seas Act and general maritime law. These
laws operate to make the liability limits established under state workers compensation laws
inapplicable to these employees. Instead, these employees or their representatives are permitted
to pursue actions against us for damages resulting from job related injuries, with generally no
limitations on our potential liability.
Employees
As of January 31, 2007, we had approximately 4,300 employees. None of our employees is represented
by a union or covered by a collective bargaining agreement. We believe that our relationship with
our employees is good.
Facilities
Our corporate headquarters are located on a 17-acre tract in Harvey, Louisiana, which we also use
to support our well intervention, marine and rental operations. Our other principal operating
facility is located on a 32-acre tract in
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Broussard, Louisiana, which we use to support our rental tools and well intervention group
operations in the Gulf of Mexico. We support the operations conducted by our liftboats from a
3.5-acre maintenance and office facility in New Iberia, Louisiana. We also own certain facilities
and lease other office, service and assembly facilities under various operating leases, including a
7-acre office and training facility located in Houston, Texas. We have a total of approximately
120 owned or leased operating facilities located in Louisiana, Texas, Alabama, Arkansas,
Mississippi, Oklahoma, Colorado, New Mexico, Utah, Wyoming, Venezuela, Australia, Trinidad, Mexico,
Colombia, the United Kingdom, the Netherlands, Eastern Canada, United Arab Emirates, and Nigeria to
support our operations. We believe that all of our leases are at competitive or market rates and
do not anticipate any difficulty in leasing suitable additional space as may be needed or extending
terms when our current leases expire.
Oil and Natural Gas Reserves
The following table presents our estimated net proved oil and natural gas reserves at December 31,
2006, 2005 and 2004 and estimated future net revenues and cash flows attributable thereto. Our
proved reserves for 2006, 2005 and 2004 were estimated by DeGolyer and MacNaughton, independent
petroleum engineers. The oil and natural reserve information contained herein do not include the
reserves owned by our equity-method investee, Coldren Resources L.P.
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As of December 31, |
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2006 |
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2005 |
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2004 |
Total estimated net proved reserves: |
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Oil (Mbbls) |
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7,921 |
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9,103 |
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9,120 |
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Natural gas (Mmcf) |
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35,641 |
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23,688 |
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29,380 |
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Total (Mboe) (1) |
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13,861 |
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13,051 |
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14,017 |
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Net proved developed reserves (4): |
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Oil (Mbbls) |
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6,709 |
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7,554 |
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7,731 |
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Natural gas (Mmcf) |
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28,982 |
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21,703 |
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25,542 |
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Total (Mboe) (1) |
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11,539 |
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11,171 |
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11,988 |
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Estimated future net revenues before income taxes
(in thousands) (2) |
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254,600 |
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$ |
441,550 |
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$ |
285,437 |
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Standardized measure of discounted future net cash
flows (in thousands) (3) |
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$ |
178,741 |
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$ |
205,105 |
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$ |
136,507 |
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(1) |
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Barrel of oil equivalents (boe) are determined using the ratio of 6 thousand cubic feet (mcf)
of natural gas to 1 barrel (bbl) of oil or condensate. Mboe, mbbls and mmcf mean a thousand boe, a
thousand bbl and a million cubic feet, respectively. |
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(2) |
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The December 31, 2006 amount was estimated by DeGolyer and MacNaughton using a period-end crude
New York Mercantile Exchange (NYMEX) price of $61.05 per bbl for oil and a NYMEX gas price of $5.64
per million British Thermal units for natural gas, and price differentials provided by us. The
December 31, 2005 amount was also estimated by DeGolyer and MacNaughton using a period-end crude
NYMEX price of $61.04 per bbl for oil and a NYMEX gas price of $9.44 per million British Thermal
units for natural gas, and price differentials provided by us. The December 31, 2004 amount was
also estimated by DeGolyer and MacNaughton using a period-end crude NYMEX price of $43.46 per bbl
for oil and a Henry Hub gas price of $6.19 per million British Thermal units for natural gas, and
price differentials provided by us. Net revenues as they appear in the table are defined as gross
revenue, less production taxes, operating expenses and capital costs. |
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The standardized measure of discounted future net cash flows, calculated by us, represents the
present value of future cash flows after income tax discounted at 10%. |
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(4) |
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Net proved developed non-producing reserves at December 31, 2006 were 3,214 mbbls (41% of total
net proved oil reserves) and 15,655 mmcf (44% of total net proved gas reserves). Net proved
undeveloped reserves as of December 31, 2006 were 1,212 mbbls (15% of total net proved oil
reserves) and 6,659 mmcf (19% of total net proved gas reserves). |
7
Since January 1, 2005 no crude oil or natural gas reserve information has been filed with, or
included in any report to any federal authority or agency other than the SEC and the Energy
Information Administration (EIA). The Company files Form 23, including reserve and other
information with the EIA.
Our reserve information is prepared in accordance with guidelines established by the Securities and
Exchange Commission, including using prices and costs determined on the date of the actual
estimate, without considering hedge contracts in place at the end of the period, and a 10% discount
rate to determine the present value of future net cash flow. There are a number of uncertainties
inherent in estimating quantities of proved reserves, including many factors beyond our control
such as commodity pricing. Therefore, the foregoing reserve information represents only estimates,
and is not intended to represent the current market value of our estimated oil and natural gas
reserves. We believe that the following factors should be taken into account in reviewing our
reserve information: (1) future costs and selling prices will differ from those required to be
used in these calculations; (2) actual rates of production achieved in future years may vary
significantly from the production rates assumed in the calculations; (3) selection of a 10%
discount rate is arbitrary and may not be reasonable as a measure of the relative risk inherent in
realizing future net oil and gas revenues; and (4) future net revenues may be subject to different
rates of income taxation.
Reserve engineering is a subjective process of estimating underground accumulations of crude oil
and natural gas that can not be measured in an exact manner. The accuracy of any reserve estimate
is a function of the quality of available data and of engineering and geological interpretation and
judgment. As a result, estimates of different engineers often vary. In addition, results of
production subsequent to the date of an estimate may justify revising the original estimate.
Accordingly, reserve estimates at any point in time are generally different from the quantities of
oil and gas that are ultimately produced. The meaningfulness of these estimates depends primarily
on the accuracy of the assumptions upon which they were based. Except to the extent we acquire
additional properties containing proved reserves, our proved reserves should decline as reserves
are produced.
Productive Wells Summary
The following table presents our ownership at December 31, 2006, of productive oil and natural gas
wells. Productive wells consist of producing wells and wells capable of production. Twenty gross
oil wells and seven gross natural gas wells have dual completions. In the table, gross refers to
the total wells in which we own an interest and net refers to the sum of fractional interests
owned in gross wells.
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
Productive Wells |
|
|
Gross |
|
Net |
Oil |
|
|
295.00 |
|
|
|
286.60 |
|
Natural gas |
|
|
71.00 |
|
|
|
57.31 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
366.00 |
|
|
|
343.91 |
|
|
|
|
|
|
|
|
|
|
As of December 31, 2006, only approximately 156 of our gross wells were actually producing. Due to
the maturity of our properties, a number of our productive wells are not able to produce on a
regular basis or without incurring significant additional costs. Accordingly, they may never
actually produce.
Acreage
The following table sets forth information as of December 31, 2006 relating to acreage held by us.
Developed acreage is assigned to productive wells.
8
|
|
|
|
|
|
|
|
|
|
|
Gross |
|
Net |
|
|
Acreage |
|
Acreage |
Developed |
|
|
130,299 |
|
|
|
102,351 |
|
Undeveloped |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
130,299 |
|
|
|
102,351 |
|
|
|
|
|
|
|
|
|
|
Drilling Activity
The following table shows our drilling activity for the years ended December 31, 2006, 2005 and
2004. We did not drill any exploratory wells during the periods covered by the table. In the
table, gross refers to the total wells in which we have a working interest and net refers to
the gross wells multiplied by our working interest in these wells. Well activity refers to the
number of wells completed during a fiscal year, regardless of when drilling first commenced. For
this table, completed refers to the installation of permanent equipment for the production of oil
and gas.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
2005 |
|
2004 |
|
|
Gross |
|
Net |
|
Gross |
|
Net |
|
Gross |
|
Net |
Development Wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive |
|
|
7.00 |
|
|
|
1.40 |
|
|
|
1.00 |
|
|
|
0.50 |
|
|
|
3.00 |
|
|
|
0.06 |
|
Non-productive |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
7.00 |
|
|
|
1.40 |
|
|
|
1.00 |
|
|
|
0.50 |
|
|
|
3.00 |
|
|
|
0.06 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
These wells were proposed and drilled under the supervision of our exploitation partners.
Costs Incurred in Oil and Natural Gas Activities
The following table displays certain information regarding the costs incurred associated with
finding, acquiring and developing our proved oil and natural gas reserves for the years ended
December 31, 2006, 2005 and 2004 (in thousands).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Acquisition of properties proved |
|
$ |
45,948 |
|
|
$ |
9,015 |
|
|
$ |
81,356 |
|
Development costs |
|
|
63,396 |
|
|
|
19,867 |
|
|
|
4,707 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred |
|
$ |
109,344 |
|
|
$ |
28,882 |
|
|
$ |
86,063 |
|
|
|
|
|
|
|
|
|
|
|
Capitalized costs for oil and gas producing activities consist of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Proved properties |
|
$ |
109,344 |
|
|
$ |
28,882 |
|
|
$ |
86,063 |
|
Accumulated depreciation, depletion and amortization |
|
|
(26,308 |
) |
|
|
(18,065 |
) |
|
|
(7,156 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalized costs, net |
|
$ |
83,036 |
|
|
$ |
10,817 |
|
|
$ |
78,907 |
|
|
|
|
|
|
|
|
|
|
|
Intellectual Property
We use several patented items in our operations that we believe are important, but not
indispensable, to our operations. Although we anticipate seeking patent protection when possible,
we rely to a greater extent on the technical expertise and know-how of our personnel to maintain
our competitive position.
9
Other Information
We have our principal executive offices at 1105 Peters Road, Harvey, Louisiana 70058. Our
telephone number is (504) 362-4321. We also have a website at http://www.superiorenergy.com.
Copies of the annual, quarterly and current reports we file with the SEC, and any amendments to
those reports, are available on our website free of charge, soon after such reports are filed with
or furnished to the SEC. The information posted on our website is not incorporated into this
Annual Report on Form 10-K. Alternatively, you may access these reports at the SECs internet
website: http://www.sec.gov/ .
We
have adopted a Code of Business Ethics and Conduct, which applies to
all of our directors, officers and employees. The Code of Business
Ethics and Conduct is publicly available on our website at
http://www.superiorenergy.com. Any waivers to the Code of Business
Ethics and Conduct by directors or executive officers and any
material amendment to the Code of Business Ethics and Conduct will be
posted promptly on our website and/or disclosed in a current report
on Form 8-K.
Item 1A. Risk Factors
You should carefully consider the following factors in addition to the other information contained
in this Annual Report. The risks described below are the material risks that we have identified.
There are many factors that affect our business and the results of our operations, many of which
are beyond our control. In addition, they may not be the only material risks that we face.
Additional risks and uncertainities not currently known to us or that we currently view as
immaterial may also impair our business operations. If any of these risks develop into actual
events, it could materially and adversely affect our business, financial condition, results of
operations and cash flows. If that occurred, the trading price of our common stock could decline
and you could lose part or all of your investment.
We are subject to the cyclical nature of the oil and gas industry.
Demand for the majority of our oilfield services is substantially dependent on the level of
expenditures by the oil and gas industry. This level of activity has traditionally been volatile
as a result of sensitivities to oil and gas prices and generally dependent on the industrys view
of future oil and gas prices. The purchases of the products and services we provide are, to a
substantial extent, deferrable in the event oil and gas companies reduce expenditures. Therefore,
the willingness of our customers to make expenditures is critical to our operations. Oil and gas
prices have historically been volatile and are affected by many factors, including:
|
|
|
the level of worldwide oil and gas exploration and production; |
|
|
|
|
the cost of exploring for, producing and delivering oil and gas; |
|
|
|
|
demand for energy, which is affected by worldwide economic activity and population growth; |
|
|
|
|
the ability of the Organization of Petroleum Exporting Countries, or OPEC, to set
and maintain production levels for oil; |
|
|
|
|
the discovery rate of new oil and gas reserves; |
|
|
|
|
political and economic uncertainty, socio-political unrest and regional instability
or hostilities; and |
|
|
|
|
technological advances affecting energy exploration, production and consumption. |
Although activity levels in production and development sectors of the oil and gas industry are less
immediately affected by changing prices and as a result, less volatile than the exploration sector,
producers generally react to declining oil and gas prices by reducing expenditures. This has in
the past adversely affected and may in the future, adversely affect our business. We are unable to
predict future oil and gas prices or the level of oil and gas industry activity. A prolonged low
level of activity in the oil and gas industry will adversely affect the demand for our products and
services and our financial condition, results of operations and cash flows.
Our industry is highly competitive.
We compete in highly competitive areas of the oilfield services industry. The products and
services of each of our principal industry segments are sold in highly competitive markets, and our
revenues and earnings may be affected by the following factors:
|
|
|
changes in competitive prices; |
|
|
|
|
fluctuations in the level of activity in major markets; |
|
|
|
|
an increased number of liftboats in the Gulf of Mexico; |
|
|
|
|
general economic conditions; and |
10
|
|
|
governmental regulation. |
We compete with the oil and gas industrys largest integrated and independent oilfield service
providers. We believe that the principal competitive factors in the market areas that we serve are
price, product and service quality, availability and technical proficiency.
Our operations may be adversely affected if our current competitors or new market entrants
introduce new products or services with better features, performance, prices or other
characteristics than our products and services. Further, additional liftboat capacity in the Gulf
of Mexico would increase competition for that service. Competitive pressures or other factors also
may result in significant price competition that could have a material adverse effect on our
results of operations and financial condition. Finally, competition among oilfield service and
equipment providers is also affected by each providers reputation for safety and quality.
Although we believe that our reputation for safety and quality service is good, we cannot guarantee
that we will be able to maintain our competitive position.
Estimates of our oil and gas reserves and potential liabilities relating to our oil and gas
properties may be incorrect.
We acquire mature oil and gas properties in the Gulf of Mexico on an as is basis and assume all
plugging, abandonment, restoration and environmental liability with limited remedies for breaches
of representations and warranties. Acquisitions of these properties require an assessment of a
number of factors beyond our control, including estimates of recoverable reserves, future oil and
gas prices, operating costs and potential environmental and plugging and abandonment liabilities.
These assessments are complex and inherently imprecise, and, with respect to estimates of oil and
gas reserves, require significant decisions and assumptions in the evaluation of available
geological, geophysical, engineering and economic data for each reservoir. In addition, since
these properties are typically mature, our facilities and operations may be more susceptible to
hurricane damage, equipment failure or mechanical problems. In connection with these assessments,
we perform due diligence reviews that we believe are generally consistent with industry practices.
However, our reviews may not reveal all existing or potential problems. In addition, our reviews
may not permit us to become sufficiently familiar with the properties to fully assess their
deficiencies and capabilities. We may not always discover structural, subsurface, environmental or
other problems that may exist or arise.
Actual future production, cash flows, development expenditures, operating and abandonment expenses
and quantities of recoverable oil and gas reserves may vary substantially from those estimated by
us and any significant variance in these assumptions could materially affect the estimated quantity
and value of our proved reserves. Therefore, the risk is that we may overestimate the value of
economically recoverable reserves and/or underestimate the cost of plugging wells and abandoning
production facilities. If costs of abandonment are materially greater or actual reserves are
materially lower than our estimates, they could have an adverse effect on earnings.
A significant portion of our revenue is derived from our non-United States operations, which
exposes us to additional political, economic and other uncertainties.
Our non-United States revenues account for approximately 15%, 14% and 16% of our total revenues
in 2006, 2005, and 2004, respectively. Our international operations are subject to a number of
risks inherent in any business operating in foreign countries including, but not limited to:
|
|
|
political, social and economic instability; |
|
|
|
|
potential seizure or nationalization of assets; |
|
|
|
|
increased operating costs; |
|
|
|
|
social unrest, acts of terrorism, war or other armed conflict; |
|
|
|
|
modification or renegotiating of contracts; |
|
|
|
|
import-export quotas; |
|
|
|
|
confiscatory taxation or other adverse tax policies; |
|
|
|
|
currency fluctuations; |
|
|
|
|
restrictions on the repatriation of funds; and |
|
|
|
|
other forms of government regulation which are beyond our control. |
11
Additionally, our competitiveness in international market areas may be adversely affected by
regulations, including, but not limited to, regulations requiring:
|
|
|
the awarding of contracts to local contractors; |
|
|
|
|
the employment of local citizens; and |
|
|
|
|
the establishment of foreign subsidiaries with significant ownership positions reserved
by the foreign government for local citizens. |
The occurrence of any of the risks described above could adversely affect our results of operations
and cash flows.
We are susceptible to adverse weather conditions in the Gulf of Mexico.
Certain areas in and near the Gulf of Mexico experience hurricanes and other extreme weather
conditions on a relatively frequent basis. Substantially all of our facilities and assets offshore
and along the Gulf of Mexico, including the structures and pipelines on our offshore oil and gas
properties, are susceptible to damage and/or total loss by these storms. Damage caused by high
winds and turbulent seas could potentially cause us to curtail both service and production
operations for significant periods of time until damage can be assessed and repaired. Moreover,
even if we do not experience direct damage from any of these storms, we may experience disruptions
in our operations because customers may curtail their development activities due to damage to their
platforms, pipelines and other related facilities.
Due to the losses as a consequence of the hurricanes that occurred in the Gulf of Mexico in 2005
and 2004, we have not been able to obtain insurance coverage comparable with that of prior years,
thus putting us at a greater risk of loss due to severe weather conditions. Any significant
uninsured losses could have a material adverse effect on our financial position, results of
operations and cash flows.
We are vulnerable to the potential difficulties associated with rapid expansion.
We have grown rapidly over the last several years through internal growth and acquisitions of other
companies. We believe that our future success depends on our ability to manage the rapid growth
that we have experienced and the demands from increased responsibility on our management personnel.
The following factors could present difficulties to us:
|
|
|
lack of sufficient executive-level personnel; |
|
|
|
|
increased administrative burden; and |
|
|
|
|
increased logistical problems common to large, expansive operations. |
If we do not manage these potential difficulties successfully, our operating results could be
adversely affected.
We depend on key personnel.
Our success depends to a great degree on the abilities of our key management personnel,
particularly our chief executive and operating officers and other high-ranking executives. The
loss of the services of one or more of these key employees could adversely affect us.
We might be unable to employ a sufficient number of skilled workers.
The delivery of our products and services require personnel with specialized skills and experience.
As a result, our ability to remain productive and profitable will depend upon our ability to
employ and retain skilled workers. In addition, our ability to expand our operations depends in
part on our ability to increase the size of our skilled labor force. The demand for skilled
workers in our industry is high, and the supply is limited. In addition, although our employees
are not covered by a collective bargaining agreement, the marine services industry has in the past
been targeted by maritime labor unions in an effort to organize Gulf of Mexico employees. A
significant increase in the wages paid by competing employers or the unionization of our Gulf of
Mexico employees could result in a reduction
12
of our skilled labor force, increases in the wage
rates that we must pay or both. If either of these events were to occur, our capacity and
profitability could be diminished and our growth potential could be impaired.
We depend on significant customers.
We derive a significant amount of our revenue from a small number of major and independent oil and
gas companies. In 2006 and 2005, Shell accounted for approximately 12% and 10% of our total
revenue, respectively. We did not have a single customer account for more than 10% of our total
revenue in 2004. Our inability to continue to perform services for a number of our large existing
customers, if not offset by sales to new or other existing customers, could have a material adverse
effect on our business and operations.
The dangers inherent in our operations and the limits on insurance coverage could expose us to
potentially significant liability costs and materially interfere with the performance of our
operations.
Our operations are subject to numerous operating risks inherent in the oil and gas industry that
could result in substantial losses. These risks include:
|
|
|
fires; |
|
|
|
|
explosions, blowouts, and cratering; |
|
|
|
|
hurricanes and other extreme weather conditions; |
|
|
|
|
mechanical problems, including pipe failure; |
|
|
|
|
abnormally pressured formations; and |
|
|
|
|
environmental accidents, including oil spills, gas leaks or ruptures, uncontrollable
flows of oil, gas, brine or well fluids, or other discharges of toxic gases or other
pollutants. |
Our liftboats are also subject to operating risks such as catastrophic marine disaster, adverse
weather conditions, collisions and navigation errors.
The occurrence of these risks could result in substantial losses due to personal injury, loss of
life, damage to or destruction of wells, production facilities or other property or equipment, or
damages to the environment. In addition, certain of our employees who perform services on offshore
platforms and marine vessels are covered by provisions of the Jones Act, the Death on the High Seas
Act and general maritime law. These laws make the liability limits established by federal and
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. In such
actions, there is generally no limitation on our potential liability.
Any litigation arising from a catastrophic occurrence involving our services, equipment or oil and
gas production operations could result in large claims for damages. The frequency and severity of
such incidents affect our operating costs, insurability and relationships with customers, employees
and regulators. Any increase in the frequency or severity of such incidents, or the general level
of compensation awards with respect to such incidents, could affect our ability to obtain projects
from oil and gas companies or insurance. We maintain several types of insurance to cover
liabilities arising from our services, including onshore and offshore non-marine operations, as
well as marine vessel operations. These policies include primary and excess umbrella liability
policies with limits of $50 million dollars per occurrence, including sudden and accidental
pollution incidents. We also maintain property insurance on our physical assets, including marine
vessels, and operating equipment. Successful claims for which we are not fully insured may
adversely affect our working capital and profitability.
For our oil and gas operations, we maintain control of well, operators extra expense and pollution
liability coverage, to include our liabilities under the federal Oil Pollution Act of 1990, or OPA.
Limits maintained for well control
incidents unrelated to windstorms range from $35 million to $50 million per occurrence. We have a limit of $75 million in
the aggregate per policy year for named windstorm related events. The liability limit is $50
million per occurrence for non-well control events. We also maintain property insurance on our
physical assets, including offshore production facilities and operating equipment. As a result of
the losses caused by recent hurricanes in the Gulf of Mexico, we experienced substantial increases
in our costs of insurance, as well as increased deductibles and self-insured retentions. Any
significant uninsured losses could have a material adverse effect on our financial position,
results of operations and cash flows.
13
The cost of many of the types of insurance coverage maintained by us has increased significantly
during recent years and resulted in the retention of additional risk by us, primarily through
higher insurance deductibles. Very few insurance underwriters offer certain types of insurance
coverage maintained by us, and there can be no assurance that any particular type of insurance
coverage will continue to be available in the future, that we will not accept retention of
additional risk through higher insurance deductibles or otherwise, or that we will be able to
purchase our desired level of insurance coverage at commercially feasible rates. Further, due to
the losses as a result of hurricanes that occurred in the Gulf of Mexico in 2005 and 2004, we were
not be able to obtain insurance coverage comparable with that of prior years, thus putting us at a
greater risk of loss due to severe weather conditions especially with our oil and gas properties.
In addition, costs have significantly increased for windstorm, or hurricane, coverage which also
impose higher deductibles and limit maximum aggregate recoveries. Any significant uninsured losses
could have a material adverse effect on our financial position, results of operations and cash
flows.
The occurrence of any of these risks could also subject us to clean-up obligations, regulatory
investigation, penalties or suspension of operations. Further, our operations may be materially
curtailed, delayed or canceled as a result of numerous factors, including:
|
|
|
the presence of unanticipated pressure or irregularities in formations; |
|
|
|
|
equipment failures or accidents; |
|
|
|
|
adverse weather conditions; |
|
|
|
|
compliance with governmental requirements; and |
|
|
|
|
shortages or delays in obtaining drilling rigs or in the delivery of equipment and services. |
Our oil and gas revenues are subject to commodity price risk.
We are subject to market risk exposure in the pricing applicable to our oil and gas production.
Considering the historical and continued volatility and uncertainty of prices received for oil and
gas production, we have and may continue to enter into hedging arrangements to reduce our exposure
to decreases in the prices of natural gas and oil.
Hedging arrangements expose us to risk of significant financial loss in some circumstances
including circumstances where:
|
|
|
there is a change in the expected differential between the underlying price in the
hedging agreement and actual prices received; |
|
|
|
|
our production and/or sales of natural gas are less than expected; |
|
|
|
|
payments owed under derivative hedging contracts typically come due prior to receipt
of the hedged months production revenue; and |
|
|
|
|
the other party to the hedging contract defaults on its contract obligations. |
We cannot assure you that the hedging transactions we enter into will adequately protect us from
declines in the prices of natural gas and oil. In addition, our hedging arrangements will limit
the benefit we would receive from increases in the prices for natural gas and oil.
14
Factors beyond our control affect our ability to market oil and gas.
The availability of markets and the volatility of product prices are beyond our control and
represent a significant risk. The marketability of our production depends upon the availability
and capacity of gas gathering systems, pipelines and processing facilities. The unavailability or
lack of capacity of these systems and facilities could result in the shut-in of producing wells or
the delay or discontinuance of development plans for properties. Our ability to market oil and gas
also depends on other factors beyond our control, including:
|
|
|
the level of domestic production and imports of oil and gas; |
|
|
|
|
the proximity of gas production to gas pipelines; |
|
|
|
|
the availability of pipeline capacity; |
|
|
|
|
the demand for oil and natural gas by utilities and other end users; |
|
|
|
|
the availability of alternate fuel sources; |
|
|
|
|
state and federal regulation of oil and gas marketing; and |
|
|
|
|
federal regulation of gas sold or transported in interstate commerce. |
If these factors were to change dramatically, our ability to market oil and gas could be adversely
affected.
Our inability to control the inherent risks of acquiring businesses could adversely affect our
operations.
Acquisitions have been and we believe will continue to be a key element of our business strategy.
We cannot assure you that we will be able to identify and acquire acceptable acquisition candidates
on terms favorable to us in the future. We may be required to incur substantial indebtedness to
finance future acquisitions. Such additional debt service requirements may impose a significant
burden on our results of operations and financial condition. We cannot assure you that we will be
able to successfully consolidate the operations and assets of any acquired business with our own
business. Acquisitions may not perform as expected when the acquisition was made and may be
dilutive to our overall operating results. In addition, our management may not be able to
effectively manage our increased size or operate a new line of business.
We may not be able to acquire oil and gas properties to increase our asset utilization.
Our strategy to increase our asset utilization by performing work on our own properties depends on
our ability to find, acquire, manage and decommission mature Gulf of Mexico oil and gas properties.
Factors that may hinder our ability to acquire these properties include competition, prevailing
oil and natural gas prices and the number of properties for sale. Another factor that could hinder
our ability to acquire oil and gas properties is our ability to
assume additional decommissioning liabilities without posting bonds or providing other financial
security to the U.S. Department of Interior, Minerals Management Service, or MMS, or the sellers of
these properties, the cost of which may render our proposal unattractive to the sellers. In
certain instances, the sellers of these properties may have continuing obligations to us that are
unsecured, and although we believe these arrangements represent minimal credit risk, we cannot
guarantee that any seller will not become a credit risk in the future. If we are unable to find
and acquire properties meeting our criteria on acceptable terms to us, we will not be able to
increase the utilization of our assets and services by performing work on our own properties during
seasonal downtime and when we have available equipment not being utilized by our traditional
customer base. We cannot guarantee that we will be able to locate and acquire such properties.
The nature of our industry subjects us to compliance with regulatory and environmental laws.
Our business is significantly affected by a wide range of local, state and federal statutes, rules,
orders and regulations relating to the oil and gas industry in general, and more specifically with
respect to the environment, health and safety, waste management and the manufacture, storage,
handling and transportation of hazardous wastes. The failure to comply with these rules and
regulations can result in the revocation of permits, corrective action orders, administrative or
civil penalties and criminal prosecution. Further, laws and regulations in this area are complex
and change frequently. Changes in laws or regulations, or their enforcement, could subject us to
material costs.
Our oil and gas operations are conducted on federal leases that are administered by MMS and are
required to comply with the regulations and orders promulgated by 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, MMS could
require us to suspend or terminate our operations on a federal lease. MMS also
establishes the basis for royalty payments due under federal oil and natural gas leases through
regulations issued under applicable statutory authority.
Our oil and gas operations are also subject to certain requirements under OPA. Under OPA and its
implementing regulations, responsible parties, including owners and operators of certain vessels
and offshore facilities, are strictly liable for damages resulting from spills of oil and other
related substances in the United States waters, subject to certain limitations. OPA also requires
a responsible party to submit proof of its financial ability to cover environmental cleanup and
restoration costs that could be incurred in connection with an oil spill. Further, OPA
15
imposes
other requirements, such as the preparation of oil spill response plans. In the event of a
substantial oil spill originating from one of our facilities, we could be required to expend
potentially significant amounts of capital which could have a material adverse effect on our future
operations and financial results.
We have compliance costs and potential environmental liabilities with respect to our offshore and
onshore operations, including our environmental cleaning services. Certain environmental laws
provide for joint and several liabilities for remediation of spills and releases of hazardous
substances. These environmental statutes may impose liability without regard to negligence or
fault. In addition, we may be subject to claims alleging personal injury or property damage as a
result of alleged exposure to hazardous substances. We believe that our present operations
substantially comply with applicable federal and state pollution control and environmental
protection laws and regulations. We also believe that compliance with such laws has not had a
material adverse effect on our operations. However, we are unable to predict whether environmental
laws and regulations will have a material adverse effect on our future operations and financial
results. Sanctions for noncompliance may include revocation of permits, corrective action orders,
administrative or civil penalties and criminal prosecution.
Federal, state and local statutes and regulations require permits for drilling operations, drilling
bonds and plugging and abandonment and reports concerning operations. Federal and state laws that
also require owners of non-producing wells to plug the well and remove all exposed piping and
rigging before the well is permanently abandoned significantly affect the demand for our plug and
abandonment services. A decrease in the level of enforcement of such laws and regulations in the
future would adversely affect the demand for our services and products. In addition, demand for
our services is affected by changing taxes, price controls and other laws and regulations relating
to the oil and gas industry generally. The adoption of laws and regulations curtailing exploration
and development drilling for oil and gas in our areas of operations for economic, environmental or
other policy reasons could also adversely affect our operations by limiting demand for our
services.
The regulatory burden on our business increases our costs and, consequently, affects our
profitability. We are unable to predict the level of enforcement of existing laws and regulations,
how such laws and regulations may be interpreted by enforcement agencies or court rulings, or
whether additional laws and regulations will be adopted. We are also unable to predict the effect
that any such events may have on us, our business, or our financial condition.
A terrorist attack or armed conflict could harm our business.
Terrorist activities, anti-terrorist efforts and other armed conflict involving the United States
may adversely affect the United States and global economies and could prevent us from meeting our
financial and other obligations. If any of these events occur, the resulting political instability
and societal disruption could reduce overall demand for oil and natural gas, potentially putting
downward pressure on demand for our services and causing a reduction in our revenues. Oil and gas
related facilities could be direct targets of terrorist attacks, and our operations could be
adversely impacted if infrastructure integral to customers operations is destroyed or damaged.
Costs for insurance and other security may increase as a result of these threats, and some
insurance coverage may become more difficult to obtain, if available at all.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
Information on properties is contained in Item 1 of this Form 10-K and in note 14 to our
consolidated financial statements included in Part II, Item 8.
16
Item 3. Legal Proceedings
We are involved in various legal and other proceedings that are incidental to the conduct of our
business. We do not believe that any of these proceedings, if adversely determined, would have a
material adverse affect on our financial condition, results of operations or cash flows.
Item 4. Submission of Matters to a Vote of Security Holders
None.
Item 4A. Executive Officers of Registrant
Terence E. Hall, age 61, has served as our Chairman of the Board and Chief Executive Officer and as
a Director since December 1995. From December 1995 to November 2004, Mr. Hall also served as our
President.
Kenneth L. Blanchard, age 57, has served as our President since November 2004, and as our Chief
Operating Officer since June 2002. Mr. Blanchard also served as one of our Executive Vice
Presidents from December 1995 to November 2004.
Robert S. Taylor, age 52, has served as our Chief Financial Officer since January 1996, as one of
our Executive Vice Presidents since September 2004, and as our Treasurer since July 1999. He also
served as one of our Vice Presidents from July 1999 to September 2004.
A. Patrick Bernard, age 49, has served as our Senior Executive Vice President of Operations since
July 2006 and as one of our Executive Vice Presidents since September 2004. He served as one of
our Vice Presidents from June 2003 until September 2004. From July 1999 until June 2003, Mr.
Bernard served as the Chief Financial Officer of our wholly-owned subsidiary International Snubbing
Services, L.L.C. and its predecessor company.
L. Guy Cook, III, age 38, has served as one of our Executive Vice Presidents since September 2004.
He has also served as an Executive Vice President of our wholly-owned subsidiary Superior Energy
Services, L.L.C. since May 2006 and a Vice President of this subsidiary and its predecessor company
since August 2000. He served as our Director of Investor Relations from April 1997 to February
2000 and was also responsible for integrating our acquisitions during that time.
James A. Holleman, age 49, has served as one of our Executive Vice Presidents since September 2004.
He served as one of our Vice Presidents from July 1999 to September 2004. Mr. Holleman has served
as an Executive Vice President since May 2006 and as a Vice President since July 1999 of Superior
Energy Services, L.L.C. From 1994 until July 1999, he served as the Chief Operating Officer of
Cardinal Services, Inc., which we acquired in July 1999 and is the predecessor to Superior Energy
Services, L.L.C.
Gregory L. Miller, age 49, has served as one of our Executive Vice Presidents since September 2004.
He has also served as the President of our wholly-owned subsidiary SPN Resources, LLC, since April
2003. From January 1991 to April 2003, Mr. Miller served as President and Chief Executive Officer
of Optimal Energy, Inc.
Danny R. Young, age 51, has served as one of our Executive Vice Presidents since September 2004.
Since May 2006, Mr. Young has served as an Executive Vice President of Superior Energy Services,
L.L.C. From January 2002 to May 2005, he served as Vice President of Health, Safety and
Environment and Corporate Services of Superior Energy Services, L.L.C.
17
PART II
Item 5. Market for Registrants Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities
Common Stock Information
Our common stock trades on the New York Stock Exchange under the symbol SPN. The following table
sets forth the high and low sales prices per share of common stock as reported for each fiscal
quarter during the periods indicated.
|
|
|
|
|
|
|
|
|
|
|
High |
|
Low |
2005 |
|
|
|
|
|
|
|
|
First Quarter |
|
$ |
19.75 |
|
|
$ |
14.58 |
|
Second Quarter |
|
|
18.46 |
|
|
|
13.71 |
|
Third Quarter |
|
|
24.10 |
|
|
|
17.64 |
|
Fourth Quarter |
|
|
23.98 |
|
|
|
17.33 |
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
|
|
|
|
|
|
First Quarter |
|
$ |
27.61 |
|
|
$ |
21.30 |
|
Second Quarter |
|
|
35.87 |
|
|
|
26.21 |
|
Third Quarter |
|
|
35.75 |
|
|
|
21.44 |
|
Fourth Quarter |
|
|
36.48 |
|
|
|
24.04 |
|
As of February 16, 2007, there were 80,636,962 shares of our common stock outstanding, which were
held by 205 record holders.
Dividend Information
We have never paid any cash dividends on our common stock. We currently expect to retain all of
the cash our business generates to fund the operation and expansion of our business.
Equity Compensation Plan Information
Information required by this item with respect to compensation plans under which our equity
securities are authorized for issuance is incorporated by reference from Part III, Item 12.
Issuer Purchases of Equity Securities
The following table provides information about the common stock repurchased during the quarter
ended December 31, 2006 in connection with our offering of 1.5% Senior Exchangeable Notes due 2026:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Approximate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dollar Value of |
|
|
|
|
|
|
|
|
|
|
|
Total Number of |
|
|
Shares that May |
|
|
|
|
|
|
|
|
|
|
|
Shares Purchased as |
|
|
Yet be |
|
|
|
Total Number of |
|
|
Average Price Paid |
|
|
Part of Publicly |
|
|
Purchased |
|
Period |
|
Shares Purchased |
|
|
per Share |
|
|
Announced Plan |
|
|
Under the Plan |
|
December 12, 2006 |
|
|
4,739,300 |
|
|
$ |
33.76 |
|
|
|
4,739,300 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18
Performance Graph
The graph and corresponding table below compares the total stockholder return on our common stock
for the last five years with the total return on the S&P 500 Index and a Self-Determined Peer Group
for the same period. The information in the graph is based on the assumption of a $100 investment
on January 1, 2002 at closing prices on December 31, 2001.
NOTES:
|
|
|
The lines represent monthly index levels derived from compounded daily returns that
include all dividends. |
|
|
|
|
The indexes are reweighted daily, using the market capitalization on the previous
trading day. |
|
|
|
|
If the monthly interval, based on the fiscal year-end, is not a trading day, the
preceding trading day is used. |
|
|
|
|
The index level for all series was set to $100.00 on December 31, 2001. |
Our Self-Determined Peer Group consists of the same peer group of twelve companies whose average
stockholder return levels comprise part of the performance criteria established by the Compensation
Committee under our long-term incentive compensation program: BJ Services Company, Helix Energy
Solutions Group, Inc., Helmerich & Payne, Inc., Oceaneering International, Inc., Oil States
International, Inc., Pride International, Inc., RPC, Inc., Seacor Holdings Inc., Smith
International, Inc., Tetra Technologies, Inc., W-H Energy Services, Inc. and Weatherford
International, Ltd.
19
Item 6. Selected Financial Data
We present below our selected consolidated financial data for the periods indicated. We derived
the historical data from our audited consolidated financial statements.
The data presented below should be read together with, and are qualified in their entirety by
reference to, Managements Discussion and Analysis of Financial Condition and Results of
Operations and our consolidated financial statements included elsewhere in this Annual Report.
The financial data is in thousands, except per share amounts.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
2006 |
|
2005 |
|
2004 |
|
2003 |
|
2002 |
Revenues |
|
$ |
1,093,821 |
|
|
$ |
735,334 |
|
|
$ |
564,339 |
|
|
$ |
500,625 |
|
|
$ |
443,147 |
|
Income from operations |
|
|
316,889 |
|
|
|
125,603 |
|
|
|
76,289 |
|
|
|
67,343 |
|
|
|
57,021 |
|
Net income |
|
|
188,241 |
|
|
|
67,859 |
|
|
|
35,852 |
|
|
|
30,514 |
|
|
|
21,886 |
|
Net income per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
2.36 |
|
|
|
0.87 |
|
|
|
0.48 |
|
|
|
0.41 |
|
|
|
0.30 |
|
Diluted |
|
|
2.32 |
|
|
|
0.85 |
|
|
|
0.47 |
|
|
|
0.41 |
|
|
|
0.30 |
|
Total assets |
|
|
1,874,478 |
|
|
|
1,097,250 |
|
|
|
1,003,913 |
|
|
|
832,863 |
|
|
|
727,620 |
|
Long-term debt, less current portion |
|
|
711,505 |
|
|
|
216,596 |
|
|
|
244,906 |
|
|
|
255,516 |
|
|
|
256,334 |
|
Decommissioning liabilities,
less current portion |
|
|
87,046 |
|
|
|
107,641 |
|
|
|
90,430 |
|
|
|
18,756 |
|
|
|
|
|
Stockholders equity |
|
|
710,688 |
|
|
|
524,374 |
|
|
|
433,879 |
|
|
|
368,129 |
|
|
|
335,342 |
|
20
Item 7. Managements Discussion and Analysis of Financial Condition and Results of
Operations
The following discussion and analysis should be read in conjunction with our consolidated financial
statements included elsewhere in this Annual Report on Form 10-K. The following information
contains forward-looking statements, which are subject to risks and uncertainties. Should one or
more of these risks or uncertainties materialize, our actual results may differ from those
expressed or implied by the forward-looking statements. See Forward-Looking Statements at the
beginning of this Annual Report on Form 10-K.
Executive Summary
We are a leading, highly diversified provider of oilfield services and equipment. We focus on
serving the drilling-related needs of oil and gas companies primarily through our rental tools
segment, and the production-related needs of oil and gas companies through our well intervention,
rental tools and marine segments. We have expanded geographically so that we now have a growing
presence in select domestic land and international market areas. We also own and operate, through
our subsidiary SPN Resources, LLC, mature oil and gas properties in the Gulf of Mexico.
The oil and gas industry remains highly cyclical and seasonal. Activity levels in our service and
rental tools segments are driven primarily by traditional energy industry activity indicators,
which include current and expected commodity prices, drilling rig counts, oil and gas production
levels, and customers spending allocated for drilling and production.
Several factors contributed to our financial performance in 2006, including:
|
|
|
increased customer spending levels on finding oil and gas reserves due to high commodity prices; |
|
|
|
|
increased customer focus on replacing reserves and increasing production through
production-enhancement projects in existing wells; |
|
|
|
|
growth in our non-Gulf of Mexico market areas; and |
|
|
|
|
extremely high demand in the Gulf of Mexico market area. |
The 2004 and 2005 hurricane seasons were a significant catalyst for Gulf of Mexico activity in
2006. First, repair work to damaged platforms and wells created demand for our liftboats, well
control, plug and abandonment, project management and engineering services. Second, storm-related
disruptions and the associated repair work delayed typical production enhancement projects,
creating pent-up demand for our production-related services and liftboats. We experienced
additional service work as these production-related projects started to get addressed during the
year. Finally, insurance costs for oil and gas operators in the Gulf of Mexico have increased
dramatically. As a result, many customers emphasized plugging and abandoning uneconomic wells in
an effort to lower their insurance costs. This also drove demand for plug and abandonment
services, liftboats and ancillary equipment in 2006.
Revenue from our non-Gulf of Mexico market areas was approximately $439 million, a 49% increase
from 2005. More than 60% of this non-Gulf of Mexico revenue, or about $270 million, was generated
from domestic land market areas. We continued to aggressively expand our rentals of accommodation
units and accessories, drill collars, drill pipe, ancillary tubulars, handling tools and
stabilizers into Arkansas, Oklahoma, Texas and the Rocky Mountains market areas. We also expanded
our well intervention services to some of these same market areas and experienced activity
increases in our existing onshore locations for coiled tubing, mechanical wireline and electric
line services.
In 2006, we continued our domestic land and international expansion strategy. We aggressively
expanded our rental tools internationally in certain international market areas, including the
North Sea, West Africa and the Middle East. In July, we announced the signing of more than $100
million of international contracts. In December, we completed our acquisition of Warrior Energy
Services Corporation, which is a provider of production-related services primarily in the major
domestic land basins.
Well Intervention Segment
21
The well intervention segment consists of specialized down-hole services, which are both labor and
equipment intensive. While our gross margin percentage tends to be fairly consistent, projects
such as emergency well control work can directly increase the gross margin percentage.
Revenue and income from operations were 38% and 222% higher, respectively, as compared to 2005.
This was due mainly to a sharp rebound in Gulf of Mexico activity following significant downtime in
2005 due to hurricanes Katrina and Rita. In the Gulf of Mexico, well control, engineering and plug
and abandonment services were utilized in hurricane recovery projects. In addition, activity in
the Gulf of Mexico for our production-related services such as coiled tubing, electric line,
hydraulic workover, mechanical wireline and pumping and stimulation also experienced significant
increases due to an increase in production-related projects. We also grew our non-Gulf of Mexico
activity as reflected by a 43% increase in this segments non-Gulf of Mexico revenue. These
increases were primarily a result of continued domestic land expansion of our production-related
services.
Rental Tools Segment
The rental tools segment consists of tools and equipment used in oil and gas drilling and
production. This segment is capital and equipment intensive. It is characterized by high gross
and operating margins due in part to relatively low operating costs. The largest fixed cost is
typically depreciation as there is little labor associated with our rental tools businesses.
Historically, pricing has not significantly fluctuated and financial performance is more of a
function of changes in volume rather than pricing.
Revenue increased 52% and income from operations increased 107% over 2005. Although pricing tends
to be stable, we were able to raise prices for many of our rental tools as a result of robust
demand in many of our market areas. The largest activity increases were in the Gulf of Mexico,
followed by the domestic land markets areas. Rentals outside the Gulf of Mexico represent more
than 60% of this segments total revenue in 2006.
Marine Segment
The marine segment consists of our 27 rental liftboats. The operating costs of our liftboats are
relatively fixed and, therefore, gross margin percentages vary significantly from
quarter-to-quarter and year-to-year primarily based on changes in dayrates and utilization levels.
As an indication of this segments performance, gross margin percentages were 60% for 2006
primarily due to dayrates that were at their highest levels in our history and high utilization.
Revenue increased 61% and income from operations increased 158% over 2005. Dayrates increased
throughout the year as a result of multiple rate increases as our liftboats were used to support
hurricane-related projects and to support the increase in traditional production-related activity.
As the year progressed, the mix of work for our liftboats shifted away from supporting construction
work associated with hurricane recovery projects as demand for production-related projects
increased.
Oil and Gas Segment
Through our subsidiary SPN Resources, LLC, we acquire, manage and decommission mature properties in
the Outer Continental Shelf of the Gulf of Mexico. As of December 31, 2006, we had interests in 31
offshore blocks containing 65 structures and approximately 156 producing wells.
The main objective of this business segment is to provide additional opportunities for our products
and services, especially during cyclical and seasonal slower periods. Because of the relatively
high fixed costs of our well intervention services, the incremental cost to work on mature
properties is far less than it would be for traditional energy producers. This segment provides
work for our services, thereby increasing utilization of our own assets by deploying services on
our own properties during periods of downtime.
The lease operating expenses for mature properties are typically relatively high because of the
amount of well intervention service work required to enhance, maintain and extend their productive
lives.
Revenues were 62% higher and income from operations was 252% higher than 2005. We spent the first
several months of the year working to restore production and repair damages caused by the active
hurricane season of 2005.
22
Production was fully restored by April. We also added production through our second quarter
acquisition of five offshore Gulf of Mexico leases. We had approximately 2,505,000 boe of
production in 2006 as compared to approximately 1,794,000 boe of production in 2005.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations are based on our
consolidated financial statements, which have been prepared in accordance with accounting
principles generally accepted in the United States. The preparation of these financial statements
requires us to make estimates and assumptions that affect the amounts reported in our consolidated
financial statements and accompanying notes. Note 1 to our consolidated financial statements
contains a description of the accounting policies used in the preparation of our financial
statements. We evaluate our estimates on an ongoing basis, including those related to long-lived
assets and goodwill, income taxes, allowance for doubtful accounts, self-insurance and oil and gas
properties. We base our estimates on historical experience and on various other assumptions that
we believe are reasonable under the circumstances. Actual amounts could differ significantly from
these estimates under different assumptions and conditions.
We define a critical accounting policy or estimate as one that is both important to our financial
condition and results of operations and requires us to make difficult, subjective or complex
judgments or estimates about matters that are uncertain. We believe that the following are the
critical accounting policies and estimates used in the preparation of our consolidated financial
statements. In addition, there are other items within our consolidated financial statements that
require estimates but are not deemed critical as defined in this paragraph.
Long-Lived Assets. We review long-lived assets for impairment whenever events or changes
in circumstances indicate that the carrying amount of any such asset may not be recoverable. We
record impairment losses on long-lived assets, including oil and gas properties, used in operations
when the estimated cash flows to be generated by those assets are less than the carrying amount of
those items. Our cash flow estimates are based upon, among other things, historical results
adjusted to reflect our best estimate of future market rates, utilization levels, operating
performance, and with respect to our oil and gas properties, future oil and natural gas sales
prices, an estimate of the ultimate amount of recoverable oil and natural gas reserves that will be
produced from a field, the timing of this future production, future costs to produce the oil and
natural gas and other factors. Our estimates of cash flows may differ from actual cash flows due
to, among other things, changes in economic conditions or changes in an assets operating
performance. If the sum of the cash flows is less than the carrying value, we recognize an
impairment loss, measured as the amount by which the carrying value exceeds the fair value of the
asset. The net carrying value of assets not fully recoverable is reduced to fair value. Our
estimate of fair value represents our best estimate based on industry trends and reference to
market transactions and is subject to variability. The oil and gas industry is cyclical and our
estimates of the period over which future cash flows will be generated, as well as the
predictability of these cash flows, can have significant impact on the carrying value of these
assets and, in periods of prolonged down cycles, may result in impairment charges.
Goodwill. In assessing the recoverability of goodwill, we must make assumptions regarding
estimated future cash flows and other factors to determine the fair value of the respective assets.
If these estimates or their related assumptions adversely change in the future, we may be required
to record material impairment charges for these assets not previously recorded. We test goodwill
for impairment in accordance with Statement of Financial Accounting Standards No. 142 (FAS No.
142), Goodwill and Other Intangible Assets. FAS No. 142 requires that goodwill as well as other
intangible assets with indefinite lives no longer be amortized, but instead tested annually for
impairment. Our annual testing of goodwill is based on our fair value and carrying value at
December 31. We estimate the fair value of each of our reporting units (which are consistent with
our reportable segments) using various cash flow and earnings projections. We then compare these
fair value estimates to the carrying value of our reporting units. If the fair value of the
reporting units exceeds the carrying amount, no impairment loss is recognized. Our estimates of
the fair value of these reporting units represent our best estimates based on industry trends and
reference to market transactions. A significant amount of judgment is involved in performing these
evaluations since the results are based on estimated future events.
Income Taxes. We provide for income taxes in accordance with Statement of Financial
Accounting Standards No. 109 (FAS No. 109), Accounting for Income Taxes. This standard takes
into account the differences between
23
financial statement treatment and tax treatment of certain transactions. 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
bases. 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. Our deferred tax calculation requires us to make certain estimates about our future
operations. Changes in state, federal and foreign tax laws, as well as changes in our financial
condition or the carrying value of existing assets and liabilities, could affect these estimates.
The effect of a change in tax rates is recognized as income or expense in the period that includes
the enactment date.
Allowance for Doubtful Accounts. We maintain an allowance for doubtful accounts for
estimated losses resulting from the inability of some of our customers to make required payments.
These estimated allowances are periodically reviewed, on a case by case basis, analyzing the
customers payment history and information regarding customers creditworthiness known to us. In
addition, we record a reserve based on the size and age of all receivable balances against which we
do not have specific reserves. If the financial condition of our customers was to deteriorate,
resulting in their inability to make payments, additional allowances may be required.
Revenue Recognition. We recognize revenue when services or equipment are provided and
collectibility is reasonably assured. Services and rentals are generally provided based on fixed
or determinable priced purchase orders or contracts with customers. We contract for marine, well
intervention and environmental projects either on a day rate or turnkey basis, with a majority of
our projects conducted on a day rate basis. Our rental tools are rented on a day rate basis, and
revenue from the sale of equipment is recognized when the equipment is shipped. We are using the
percentage-of-completion method for recognizing our revenues and related costs on our contract to
construct a derrick barge for a third party. We are estimating the percentage complete utilizing
engineering estimates and construction progress. We recognize oil and gas revenue from our
interests in producing wells as the commodities are delivered, and the revenue is recorded net of
royalties and hedge payments due or inclusive of hedge payments receivable.
Self-Insurance. We self-insure, through deductibles and retentions, up to certain levels
for losses related to workers compensation, marine protection and indemnity, general liability,
property damage, and group medical. With the recent contractions of insurance availability, we
have been forced to retain more risk by increasing our self-insurance. We accrue for these
liabilities based on estimates of the ultimate cost of claims incurred as of the balance sheet
date. We regularly review our estimates of reported and unreported claims and provide for losses
through reserves. We also have an actuary review our estimates for losses related to workers
compensation and group medical on an annual basis. While we believe these estimates are reasonable
based on the information available, our financial results could be impacted if litigation trends,
claims settlement patterns and future inflation rates are different from our estimates. Although
we believe adequate reserves have been provided for expected liabilities arising from our
self-insured obligations, and we believe that we maintain adequate insurance coverage, we cannot
assure that such coverage will adequately protect us against liability from all potential
consequences.
Oil and Gas Properties. Our subsidiary, SPN Resources, LLC, acquires mature oil and gas
properties and assumes the related well abandonment and decommissioning liabilities. We follow the
successful efforts method of accounting for our investment in oil and natural gas properties.
Under the successful efforts method, the costs of successful exploratory wells and leases
containing productive reserves are capitalized. Costs incurred to drill and equip developmental
wells, including unsuccessful development wells, are capitalized. Other costs such as geological
and geophysical costs and the drilling costs of unsuccessful exploratory wells are expensed. SPN
Resources property purchases are recorded at the value exchanged at closing, combined with an
estimate of its proportionate share of the decommissioning liability assumed in the purchase. 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 units-of-production basis based on the
estimated remaining equivalent proved oil and gas reserves of each field. Well costs are depleted
on a units-of-production basis based on the estimated remaining equivalent proved developed oil and
gas reserves of each field.
We estimate the third party market price to plug and abandon wells, abandon the pipelines,
decommission and remove the platforms and clear the sites, and use that estimate to record our
proportionate share of the decommissioning liability. In estimating the decommissioning
liabilities, we perform detailed estimating procedures, analysis and engineering studies. Whenever
practical, we will utilize the services of our subsidiaries to
24
perform well abandonment and decommissioning work. When these services are performed by our
subsidiaries, all recorded intercompany revenues and expenses 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 incurred 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 liability whenever
indicators suggest that the estimated cash flows underlying the liability 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 recorded, which in turn would increase the
carrying values of the related properties.
Oil and gas properties are assessed for impairment in value on a field-by-field basis whenever
indicators become evident. We use our current estimate of future revenues and operating expenses
to test the capitalized costs for impairment. In the event net undiscounted cash flows are less
than the carrying value, an impairment loss is recorded based on the present value of expected
future net cash flows over the economic lives of the reserves.
Proved Reserve Estimates. Our reserve information is prepared by independent reserve
engineers in accordance with guidelines established by the Securities and Exchange Commission.
There are a number of uncertainties inherent in estimating quantities of proved reserves, including
many factors beyond our control such as commodity pricing. Reserve engineering is a subjective
process of estimating underground accumulations of crude oil and natural gas that can not be
measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment. In accordance with
the Securities and Exchange Commissions guidelines, we use prices and costs determined on the date
of the actual estimate and a 10% discount rate to determine the present value of future net cash
flow. Actual prices and costs may vary significantly, and the discount rate may or may not be
appropriate based on outside economic conditions.
Comparison of the Results of Operations for the Years Ended December 31, 2006 and 2005
For the year ended December 31, 2006, our revenues were $1,093.8 million, resulting in net income
of $188.2 million or $2.32 diluted earnings per share. Our net income includes a loss on early
extinguishment of debt of $12.6 million. For the year ended December 31, 2005, revenues were
$735.3 million, and net income was $67.9 million or $0.85 diluted earnings per share. We
experienced significantly higher revenues and gross margins for our well intervention, rental tools
and marine segments due to higher pricing and utilization for most products and services offered.
Factors driving our improved performance include higher commodity prices resulting in additional
production and drilling-related activity worldwide, as well as demand for our services and
liftboats that are necessary to assist in repair work needed as the result of the active Gulf of
Mexico hurricane seasons of 2004 and 2005.
The following table compares our operating results for the years ended December 31, 2006 and 2005.
Gross margin is calculated by subtracting cost of services from revenue for each of our four
business segments. Oil and gas eliminations represent products and services provided to the oil
and gas segment by the Companys other three segments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue |
|
Gross Margin |
|
|
2006 |
|
2005 |
|
Change |
|
2006 |
|
% |
|
2005 |
|
% |
|
Change |
|
|
|
|
|
Well Intervention |
|
$ |
469,110 |
|
|
$ |
339,609 |
|
|
$ |
129,501 |
|
|
$ |
199,479 |
|
|
|
43 |
% |
|
$ |
125,971 |
|
|
|
37 |
% |
|
$ |
73,508 |
|
Rental Tools |
|
|
371,155 |
|
|
|
243,536 |
|
|
|
127,619 |
|
|
|
255,257 |
|
|
|
69 |
% |
|
|
160,974 |
|
|
|
66 |
% |
|
|
94,283 |
|
Marine |
|
|
140,115 |
|
|
|
87,267 |
|
|
|
52,848 |
|
|
|
83,926 |
|
|
|
60 |
% |
|
|
39,278 |
|
|
|
45 |
% |
|
|
44,648 |
|
Oil and Gas |
|
|
127,682 |
|
|
|
78,911 |
|
|
|
48,771 |
|
|
|
57,654 |
|
|
|
45 |
% |
|
|
33,107 |
|
|
|
42 |
% |
|
|
24,547 |
|
Less: Oil and Gas Elim. |
|
|
(14,241 |
) |
|
|
(13,989 |
) |
|
|
(252 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
1,093,821 |
|
|
$ |
735,334 |
|
|
$ |
358,487 |
|
|
$ |
596,316 |
|
|
|
55 |
% |
|
$ |
359,330 |
|
|
|
49 |
% |
|
$ |
236,986 |
|
|
|
|
|
|
The following discussion analyzes our results on a segment basis.
25
Well Intervention Segment
Revenue for our well intervention segment was $469.1 million for the year ended December 31, 2006,
as compared to $339.6 million for 2005. This segments gross margin percentage increased to 43% in
2006 from 37% in 2005. We experienced higher revenue for most of our production-related services
as pricing and utilization were higher due to increased demand for production-related services and
hurricane-related repair work in the Gulf of Mexico. In addition, revenue increased for our plug
and abandonment services as many customers continue to plug severely damaged wells and temporarily
or permanently plug other wells to lower their insurance exposure and risk of damage from any
future hurricanes. We also increased our revenues in the domestic onshore markets and acquired
Warrior Energy Services Corporation in December 2006 to further this expansion and strengthen this
segment.
Rental Tools Segment
Revenue for our rental tools segment for 2006 was $371.2 million, a 52% increase over 2005. The
gross margin percentage increased to 69% in 2006 from 66% in 2005. We experienced significant
increases in revenue from our stabilizers, on-site accommodations, drill pipe and accessories,
specialty tubulars and drill collars. The increases are primarily the result of significant
increases in activity in the Gulf of Mexico, domestic land markets, as well as our international
expansion efforts. Our international revenue for the rental tools segment has increased 73% to
approximately $95 million for 2006 over 2005.
Marine Segment
Our marine segment revenue for the year ended December 31, 2006 increased 61% over 2005 to $140.1
million. The gross margin percentage for 2006 increased to 60% from 45% in 2005. The year ended
December 31, 2006 was characterized by a significant increase in liftboat pricing and utilization
due to increased demand resulting from increases in Gulf of Mexico production-related activity and
ongoing construction and repair work as a result of the damage in the Gulf of Mexico from
Hurricanes Katrina and Rita. The fleets average dayrate increased over 80% to approximately
$16,600 in 2006 from $9,200 in 2005. The fleets average utilization increased to approximately
82% in 2006 from 78% in 2005. The year ended December 31, 2005 also included five months of rental
activity from the 105-foot and the 120 to 135-foot class liftboats, which were sold June 1, 2005.
Oil and Gas Segment
Oil and gas revenues were $127.7 million in the year ended December 31, 2006, as compared to $78.9
million in 2005. In 2006, production was approximately 2,505,000 boe, as compared to approximately
1,794,000 boe in 2005. The gross margin percentage increased to 45% in 2006 from 42% in 2005 due
to increased production and commodity prices, despite increased insurance cost and repair costs
related to Hurricanes Katrina and Rita. The oil and gas segment also benefited from the additional
production as a result of the acquisition of the offshore Gulf of Mexico leases in April 2006.
Depreciation, Depletion, Amortization and Accretion
Depreciation, depletion, amortization and accretion increased to $111.0 million in the year ended
December 31, 2006 from $89.3 million in 2005. The increase results from the depreciation
associated with our 2006 and 2005 capital expenditures primarily in the rental tools segment, as
well as additional depletion associated with increased oil and gas production.
General and Administrative Expenses
General and administrative expenses increased to $168.4 million for the year ended December 31,
2006 from $141.0 million in 2005. This increase was primarily
attributable to increased expense related to our continued growth
through expanding our geographic area of operations and acquisitions
as well as increased incentive compensation expense due to our
strong operating results. General and administrative expenses decreased
to 15% of revenue for 2006 from 19% in 2005.
26
Comparison of the Results of Operations for the Years Ended December 31, 2005 and 2004
For the year ended December 31, 2005, our revenues were $735.3 million resulting in net income of
$67.9 million or $0.85 diluted earnings per share. For the year ended December 31, 2004, revenues
were $564.3 million and net income was $35.9 million or $0.47 diluted earnings per share. We
experienced higher revenue and gross margin in all our segments, especially our rental tools, oil
and gas and well intervention segments as activity levels increased. However, the extraordinarily
active hurricane season disrupted most of our activity for several months following Hurricanes
Katrina and Rita.
The following table compares our operating results for the years ended December 31, 2005 and 2004.
Gross margin is calculated by subtracting cost of services from revenue for each of our four
business segments. Oil and gas eliminations represent products and services provided to the oil
and gas segment by the Companys three other segments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue |
|
Gross Margin |
|
|
2005 |
|
2004 |
|
Change |
|
2005 |
|
% |
|
2004 |
|
% |
|
Change |
|
|
|
|
|
Well Intervention |
|
$ |
339,609 |
|
|
$ |
295,690 |
|
|
$ |
43,919 |
|
|
$ |
125,971 |
|
|
|
37 |
% |
|
$ |
105,832 |
|
|
|
36 |
% |
|
$ |
20,139 |
|
Rental Tools |
|
|
243,536 |
|
|
|
170,064 |
|
|
|
73,472 |
|
|
|
160,974 |
|
|
|
66 |
% |
|
|
112,711 |
|
|
|
66 |
% |
|
|
48,263 |
|
Marine |
|
|
87,267 |
|
|
|
69,808 |
|
|
|
17,459 |
|
|
|
39,278 |
|
|
|
45 |
% |
|
|
20,227 |
|
|
|
29 |
% |
|
|
19,051 |
|
Oil and Gas |
|
|
78,911 |
|
|
|
37,008 |
|
|
|
41,903 |
|
|
|
33,107 |
|
|
|
42 |
% |
|
|
15,461 |
|
|
|
42 |
% |
|
|
17,646 |
|
Less: Oil and Gas Elim. |
|
|
(13,989 |
) |
|
|
(8,231 |
) |
|
|
(5,758 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
735,334 |
|
|
$ |
564,339 |
|
|
$ |
170,995 |
|
|
$ |
359,330 |
|
|
|
49 |
% |
|
$ |
254,231 |
|
|
|
45 |
% |
|
$ |
105,099 |
|
|
|
|
|
|
The following discussion analyzes our operating results on a segment basis.
Well Intervention Segment
Revenue for our well intervention segment was $339.6 million for the year ended December 31, 2005,
as compared to $295.7 million for 2004. This segments gross margin percentage increased slightly
to 37% in 2005 from 36% in 2004. We experienced higher revenue for almost all of our services as
production-related activity improved in the Gulf of Mexico, particularly for the well control,
hydraulic workover, coiled tubing, wireline and field management services. Activity levels
declined in the months following Hurricanes Katrina and Rita, but pre-storm demand levels returned
near the end of the year.
Rental Tools Segment
Revenue for our rental tools segment for the year ended December 31, 2005 was $243.5 million, a
43% increase over 2004. The gross margin percentage remained unchanged at 66% for the years ended
December 31, 2005 and 2004. We experienced significant increases in revenue from our on-site
accommodations, drill pipe and accessories and stabilizers. The increases are primarily the
result of significant increases in activity in the Gulf of Mexico, as well as our international
and domestic expansion efforts. Although our rental tools segment was negatively impacted from
Hurricanes Katrina and Rita in August and September of 2005, activity levels surpassed pre-storm
levels for most of our rental tools by the end of the year. Our international revenue for the
rental tools segment has increased 108% to approximately $53.6 million for the year ended December
31, 2005 from 2004. Our biggest improvements were in the North Sea, Trinidad, Venezuela and
Mexico.
Marine Segment
Our marine segment revenue for the year ended December 31, 2005 increased 25% over 2004 to $87.3
million. The gross margin percentage for the year ended December 31, 2005 increased to 45% from
29% for 2004. The year ended December 31, 2005 includes only five months of rental activity from
the 105-foot and the 120 to 135-foot class liftboats. These 17 rental liftboats were sold
effective June 1, 2005. The increase in revenue is caused by increased utilization of our fleets
remaining larger liftboats at higher dayrates partially offset by fewer liftboats generating
revenue for seven months of 2005. The increase in the gross margin percentage is also caused by
27
increased demand and the sale of our lower margin rental liftboats. The fleets average dayrate
increased 47% to approximately $9,200 in the year ended December 31, 2005 from approximately
$6,300 in 2004. Increased demand as well as the sale of the smaller liftboats also contributed to
the increase in average dayrates. The fleets average utilization increased to approximately 78%
for the year ended December 31, 2005 from 72% in 2004. Our liftboat fleet experienced strong
increases in demand and pricing in the fourth quarter as liftboats were needed for the large
amount of construction and repair work in the Gulf of Mexico as a result of hurricane damage.
Oil and Gas Segment
Oil and gas revenues were $78.9 million in the year ended December 31, 2005 as compared to $37.0
million in 2004. The increase in revenue is primarily the result of production from South Pass 60,
which was acquired in July 2004, and production from West Delta 79/86, which was acquired in
December 2004. We also acquired Galveston 241/255 and High Island A-309 in late-July 2005. In the
year ended December 31, 2005, production was approximately 1,794,000 boe as compared to
approximately 918,000 boe in 2004. The gross margin percentage remained unchanged at 42% for the
years ended December 31, 2005 and 2004. The oil and gas segment was affected by significant
amounts of curtailed production resulting from the active hurricane seasons the past two years
resulting in deferred production as a result of Hurricanes Katrina and Rita in 2005 of
approximately 744,000 boe and as a result of Hurricane Ivan in 2004 of approximately 347,000 boe.
Depreciation, Depletion, Amortization and Accretion
Depreciation, depletion, amortization and accretion increased to $89.3 million in the year ended
December 31, 2005 from $67.3 million in 2004. The increase is primarily a result of depletion and
accretion related to our oil and gas properties from both increased production and acquisitions of
oil and gas properties. The increase also results from the depreciation associated with our 2005
and 2004 capital expenditures primarily in the rental tools segment.
General and Administrative
General and administrative expenses increased to $141.0 million for the year ended December 31,
2005 from $110.6 million in 2004. Of this increase, $5.5 million is the result of storm-related
costs from Hurricanes Katrina and Rita in the third and fourth quarters of 2005 including $2.1
million in equipment and facility losses and repairs, $2.0 million in relief aid to more than 560
employees affected by the hurricanes and $1.4 million in storm-related payroll expenses, temporary
lodging and miscellaneous expenses. The remaining increase was primarily related to increased
payroll and bonus expenses, increased insurance costs and expenses as a result of our growth, oil
and gas acquisitions and geographic expansion.
Reduction in Value of Assets
During the year ended December 31, 2005, we reduced the value of two of our mature oil and gas
properties by approximately $2.1 million, thereby removing the reserve balance associated with
these wells. The wells were deemed to be uneconomical to further produce as a result of the
estimated costs associated with maintaining production.
Our oil spill containment boom manufacturing facility suffered damage from Hurricane Katrina and
experienced difficulty in resuming normal business operations. As a result, we elected not to
reopen this manufacturing facility and sell the remaining oil spill containment boom inventory. We
reduced the value of the assets of this business (which consist primarily of inventory and property
and equipment) by approximately $1.1 million to the estimated net realizable value.
In the first quarter of 2006, we sold our environmental subsidiary for approximately $18.7 million
in cash. We reduced the net asset value of this subsidiary by $3.8 million in 2005 to its
approximate sales price.
Gain on Sale of Liftboats
Effective June 1, 2005, we sold all of our rental liftboats with leg-lengths from 105 feet to 135
feet for $19.8 million in cash (exclusive of costs to sell), which resulted in a gain of $3.5
million.
28
Liquidity and Capital Resources
In the year ended December 31, 2006, we generated net cash from operating activities of $280.2
million as compared to $158.4 million in 2005. Our primary liquidity needs are for working
capital, capital expenditures, acquisitions and debt service. Our primary sources of liquidity are
cash flows from operations and borrowings under our revolving credit facility. We also issued $300
million of 6 7/8% Senior Notes and $400 million of 1.5% Senior Exchangeable Notes to satisfy our
liquidity needs in 2006. We had cash and cash equivalents of $39.0 million at December 31,
2006 compared to $54.5 million at December 31, 2005.
We made approximately $242.9 million of capital expenditures during the year ended December 31,
2006, of which approximately $109.6 million was used to expand and maintain our rental tool
equipment inventory. We also made $64.3 million of capital expenditures in our oil and gas segment
and $65.2 million of capital expenditures to expand and maintain the asset base of our well
intervention and marine segments, including $5.9 million related to anchor handling tugs, $20.6
million related to the completion of our first derrick barge and $3.1 million of progress payments
related to the construction of another derrick barge. In addition, we made $3.8 million of capital
expenditures on construction and improvements to our facilities.
On December 12, 2006, we acquired Warrior Energy Services Corporation for a total purchase price of
approximately $374.1 million. The total consideration was comprised of cash payments of $237.8
million (including acquisition costs and repayment of debt) and equity consideration of $136.3
million (5,369,888 shares of Superior common stock valued at $25.39 per share, the average closing
market price per share for the five trading day period beginning two trading days before the merger
announcement date of September 25, 2006). Warrior is an oil and gas services company that provides
various well intervention services and rental tools and equipment onshore in Alabama, Arkansas,
Colorado, Kansas, Louisiana, Mississippi, Montana, New Mexico, North Dakota, Oklahoma, Texas, Utah
and Wyoming, and offshore in the Gulf of Mexico.
We acquired a 40% interest in Coldren Resources which acquired substantially all of Nobles shallow
water Gulf of Mexico oil and gas properties in July 2006. We have made a total cash investment in
Coldren Resources of approximately $57.8 million as of December 31, 2006. We do not anticipate
additional cash investments in Coldren Resources.
During the year ended December 31, 2006, we paid $46.6 million to acquire producing oil and gas
properties located on five offshore Gulf of Mexico leases and purchased two businesses for
approximately $9.8 million. We also sold our environmental cleaning subsidiary for approximately
$18.7 million during the first quarter of 2006.
In July 2006, we took delivery of an 880-ton derrick barge. The final payment of $13.3 million was
made upon its delivery and acceptance. The derrick barge and related anchor handling tug are
chartered to a third party until October 31, 2007.
In July 2006, we contracted to construct a derrick barge that will be sold to a third party for
approximately $54 million. We expect to take delivery of the derrick barge and sell it to the
third party during the first quarter of 2008. We receive monthly payments from the purchaser in
accordance with the terms of the sales contract. In turn, we issue letters of credit to the
purchaser in equal amounts to guarantee our performance of the contract. We have entered into
fixed-price contracts to construct this second derrick barge and its 880-ton offshore mast crane.
Our payment obligation for the construction of the barge is secured by letters of credit that are
posted upon performance milestones and are payable upon the barges delivery and our acceptance.
The contract for the crane requires periodic progress payments with final payment due upon
completion of the contract. Revenue and costs associated with the sale contract are accounted for
on the percentage-of-completion method utilizing engineering estimates and
construction progress. This methodology requires us to make estimates regarding our progress
against the project schedule and estimated completion date, both of which impact the amount of
revenue and gross margin we recognize in each reporting period. Contract costs mainly include
sub-contract and program management costs. Provisions for any anticipated losses will be recorded
in full when such losses become evident.
In July 2006, we contracted to construct a third derrick barge to support our decommissioning and
construction operations. We expect to take delivery of this barge in the second quarter of 2008.
We have entered into fixed-price
29
contracts to construct this derrick barge and its 880-ton offshore
mast crane. Our payment obligation for the construction of the barge is secured by letters of
credit that are posted upon performance milestones and are payable upon the barges delivery and
our acceptance. The contract for the crane requires periodic progress payments with final payment
due upon completion of the contract. We currently intend to utilize this construction barge to
support our removal projects in the Gulf of Mexico market area for both third party customers and
our subsidiary, SPN Resources.
We amended our revolving credit facility in the fourth quarter of 2006 increasing it to $250
million from $150 million. Any amounts outstanding under the revolving credit facility are due on
June 14, 2011. At February 16, 2006, we had $27.1 million outstanding under the bank credit
facility at an interest rate of 7.6% per annum. We also had approximately $54.5 million of letters
of credit outstanding, which reduces our borrowing capacity under this credit facility. Borrowings
under the credit facility bear interest at a LIBOR rate plus margins that depend on our leverage
ratio. Indebtedness under the credit facility is secured by substantially all of our assets,
including the pledge of the stock of our principal subsidiaries. The credit facility contains
customary events of default and requires that we satisfy various financial covenants. It also
limits our ability to pay dividends or make other distributions, make acquisitions, create liens,
incur additional indebtedness or assume additional decommissioning liabilities.
We have $16.6 million outstanding at December 31, 2006 in U. S. Government guaranteed long-term
financing under Title XI of the Merchant Marine Act of 1936, which is administered by the Maritime
Administration (MARAD), for two 245-foot class liftboats. This debt bears an interest rate of
6.45% per annum and is payable in equal semi-annual installments of $405,000 on every June
3rd and December 3rd through June 3, 2027. Our obligations are secured by
mortgages on the two liftboats. This MARAD financing also requires that we comply with certain
covenants and restrictions, including the maintenance of minimum net worth and debt-to-equity
requirements.
In the second quarter of 2006, we completed a tender offer for approximately 97.6% of our $200
million outstanding of 8 7/8% unsecured senior notes due 2011. The cash consideration for the
tender offer was $1,045.63 per $1,000 in aggregate principal amount of senior notes tendered. In
conjunction with the tender offer, we also received consents to amend the indenture pursuant to
which the senior notes were issued to eliminate from the indenture substantially all of the
restrictive covenants and certain events of default. After the tender offer was completed, we
redeemed the remaining outstanding senior notes in accordance with the indenture at the redemption
price of $1,044.38 per $1,000 of the principal amount redeemed. We recognized a loss on the early
extinguishment of debt of approximately $12.6 million, which included the tender premiums,
redemption premiums, fees and expenses and the write-off of the remaining unamortized debt
acquisition costs associated with these notes.
We issued $300 million of 6 7/8% unsecured senior notes due 2014. We used the net proceeds to
refinance the 8 7/8% senior notes due 2011 and related tender and redemption premiums, fees and
related expenses, and to fund the equity investment in Coldren Resources. The indenture governing
the notes requires semi-annual interest payments, on every June 1st and December
1st through the maturity date of June 1, 2014. The indenture contains certain covenants
that, among other things, restrict us from incurring, additional debt, repurchasing capital stock,
paying dividends or making other distributions, incurring liens, selling assets or entering into
certain mergers or acquisitions.
In December 2006, we issued $400 million of 1.50% Senior Exchangeable Notes due 2026. The notes
bear interest at a rate of 1.50% per annum and decrease to 1.25% per annum on December 15, 2011.
Interest on the notes is payable semi-annually in arrears on December 15th and June
15th of each year, beginning June 15, 2007. The notes do not contain any restrictive
financial covenants.
Under certain circumstances, holders may exchange the notes for shares of our common stock. The
initial exchange rate is 21.9414 shares of common stock per $1,000 principal amount of notes. This
is equal to an initial exchange price of $45.58 per share. The exchange price represents a 35%
premium over the closing share price at the date of issuance. The notes may be exchanged under the
following circumstances:
|
|
|
during any fiscal quarter (and only during such fiscal quarter) commencing after March
31, 2007, if the last reported sale price of our common stock is greater than or equal to
135% of the applicable exchange price |
30
|
|
|
of the notes for at least 20 trading days in the
period of 30 consecutive trading days ending on the last trading day of the preceding
fiscal quarter; |
|
|
|
|
prior to December 15, 2011, during the five business-day period after any ten
consecutive trading-day period (the measurement period) in which the trading price of
$1,000 principal amount of notes for each trading day in the measurement period was less
than 95% of the product of the last reported sale price of our common stock and the
exchange rate on such trading day; |
|
|
|
|
if the notes have been called for redemption; |
|
|
|
|
upon the occurrence of specified corporate transactions; or |
|
|
|
|
at any time beginning on September 15, 2026, and ending at the close of business on the
second business day immediately preceding the maturity date. |
In connection with the exchangeable note transaction, we simultaneously entered into agreements
with affiliates of the initial purchasers to purchase call options and sell warrants on our common
stock. We may exercise the call options we purchased at any time to acquire approximately 8.8
million shares of our common stock at a strike price of $45.58 per share. The owners of the
warrants may exercise the warrants to purchase from us approximately 8.8 million shares of our
common stock at a price of $59.42 per share, subject to certain anti-dilution and other customary
adjustments. The warrants may be settled in cash, in shares or in a combination of cash and
shares, at our option. These transactions may potentially reduce the dilution of our common stock
from the exchange of the notes by increasing the effective exchange price to $59.42 per share.
We paid $96 million (exclusive of a $35.5 million tax benefit) to acquire the call options and
received $60.4 million as a result of the sale of the warrants.
In December 2006, concurrently with the closing of our 1.5% Senior Exchangeable Notes, we
repurchased 4,739,300 shares of our outstanding common stock at a price of $33.76 per share, or
approximately $160 million in the aggregate, in privately negotiated block trades through one of
the initial purchasers of the notes.
The following table summarizes our contractual cash obligations and commercial commitments at
December 31, 2006 (amounts in thousands) for our long-term debt (including estimated interest
payments), decommissioning liabilities, operating leases and contractual obligations. The
decommissioning liability amounts do not give any effect to our contractual right to receive
amounts from third parties, which is approximately $31.0 million, when decommissioning operations
are performed. The derrick barge and tug construction obligation amounts do not give any effect to
our contractual right to receive payments from a third-party customer, which is approximately $41.2
million. We do not have any other material obligations or commitments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Description |
|
2007 |
|
2008 |
|
2009 |
|
2010 |
|
2011 |
|
Thereafter |
|
Long-term debt, including
estimated interest
payments |
|
$ |
28,492 |
|
|
$ |
28,440 |
|
|
$ |
28,388 |
|
|
$ |
28,336 |
|
|
$ |
27,783 |
|
|
$ |
845,578 |
|
Decommissioning liabilities |
|
|
35,150 |
|
|
|
5,743 |
|
|
|
2,371 |
|
|
|
10,271 |
|
|
|
29,390 |
|
|
|
39,271 |
|
Operating leases |
|
|
7,003 |
|
|
|
4,939 |
|
|
|
2,932 |
|
|
|
1,628 |
|
|
|
973 |
|
|
|
13,692 |
|
Derrick barge and tug
construction |
|
|
26,332 |
|
|
|
45,562 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
96,977 |
|
|
$ |
84,684 |
|
|
$ |
33,691 |
|
|
$ |
40,235 |
|
|
$ |
58,146 |
|
|
$ |
898,541 |
|
|
|
|
We have no off-balance sheet arrangements other than our potential additional consideration that
may be payable as a result of the future operating performances of our acquisitions. At December
31, 2006, the maximum additional consideration payable for our prior acquisitions was approximately
$2.4 million. These amounts are not classified
as liabilities under generally accepted accounting principles and are not reflected in our
financial statements until the amounts are fixed and determinable. When amounts are determined,
they are capitalized as part of the purchase price of the related acquisition. We do not have any
other financing arrangements that are not required under generally accepted accounting principles
to be reflected in our financial statements.
We currently believe that we will make approximately $362 million of capital expenditures,
excluding acquisitions and targeted asset purchases, during 2007 to expand our rental tool asset
base, add new coiled tubing and electric-line units, construct our derrick barges and perform
workovers on SPN Resources oil and gas properties. We
31
believe that our current working capital,
cash generated from our operations and availability under our revolving credit facility will
provide sufficient funds for our identified capital projects.
We intend to continue implementing our growth strategy of increasing our scope of services through
both internal growth and strategic acquisitions. We expect to continue to make the capital
expenditures required to implement our growth strategy in amounts consistent with the amount of
cash generated from operating activities, the availability of additional financing and our credit
facility. Depending on the size of any future acquisitions, we may require additional equity or
debt financing in excess of our current working capital and amounts available under our revolving
credit facility.
Hedging Activities
We entered into hedging transactions in 2004 that expired on August 31, 2006 to secure a commodity
price for a portion of our oil production and to reduce our exposure to oil price fluctuations. We
do not enter into derivative transactions for trading purposes. We used financially-settled crude
oil swaps and zero-cost collars that provided floor and ceiling prices with varying upside price
participation. Our swaps and zero-cost collars were designated and accounted for as cash flow
hedges. We have not hedged any of our natural gas production. We recognized the fair value of all
derivative instruments as assets or liabilities on the balance sheet. Changes in the fair value of
cash flow hedges, to the extent the hedge was effective, were recognized in other comprehensive
income until the hedged item was settled and recorded in oil and gas revenues. For the year ended
December 31, 2006, hedging settlement payments reduced oil and gas revenues by approximately $13.8
million, and no gains or losses were recognized due to hedge ineffectiveness.
Recently Issued Accounting Pronouncements
In February 2006, the Financial Accounting Standards Board issued its Statement of Financial
Accounting Standards No. 155 (FAS No. 155), Accounting for Certain Hybrid Financial Instruments
an amendment of FASB Statements No. 133 and 140. FAS No. 155 simplifies accounting for certain
hybrid financial instruments by permitting fair value remeasurement for any hybrid instrument that
contains an embedded derivative that otherwise would require bifurcation and eliminates a
restriction on the passive derivative instruments that a qualifying special-purpose entity may
hold. FAS No. 155 is effective for all financial instruments acquired, issued or subject to a
remeasurement (new basis) event occurring after the beginning of an entitys first fiscal year that
begins after September 15, 2006. The adoption of FAS No. 155 has not had an impact on our results
of operations or our financial position.
In July 2006, the Financial Accounting Standards Board issued FASB Interpretation No. 48 (FIN 48),
Accounting for Uncertainty in Income Taxes an interpretation of FASB Statement No. 109. FIN 48
provides guidance on measurement and recognition in accounting for income tax uncertainties and
also requires expanded financial statement disclosure. This interpretation is effective for fiscal
years beginning after December 15, 2006. We have evaluated the impact of FIN 48 and do not expect
it to have a material impact on our results of operations or financial condition.
In September 2006, the Financial Accounting Standards Board issued its Statement of Financial
Accounting Standards No. 157 (FAS No. 157), Fair Value Measurements. FAS No. 157 establishes a
framework for measuring fair value in generally accepted accounting principles, and expands
disclosures about fair value measurements. FAS No. 157 is effective for financial statements
issued for fiscal years beginning after November 15, 2007. We are currently evaluating the impact
that FAS No. 157 will have on our results of operations and financial position.
In September 2006, the Financial Accounting Standards Board issued its Statement of Financial
Accounting Standards No. 158 (FAS No. 158), Employers Accounting for Defined Benefit Pension and
Other Postretirement Plans an Amendment of FASB Statements No. 87, 88, 106, and 132(R). FAS No.
158 requires recognition of the overfunded or underfunded status of a defined benefit
postretirement plan (other than a multiemployer plan) as an asset or liability on the balance sheet
and the recognition of changes in the funded status in the year in which the changes occur though
comprehensive income. FAS No. 158 also requires an employer to measure the funded status of a plan
as of the end of the fiscal year. FAS No. 158 is effective for fiscal years ending after December
15, 2006,
32
except for the measurement date provisions which are effective for fiscal years ending
after December 15, 2008. The adoption of FAS No. 158 has not had an impact on our results of
operations or our financial position.
In September 2006, the Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin
No. 108 (SAB 108), Considering the Effects of Prior Year Misstatements when Quantifying
Misstatements in Current Year Financial Statements. SAB 108 provides guidance on the
consideration of effects of prior year misstatements in quantifying current year misstatements for
the purpose of a materiality assessment. SAB 108 requires the analysis of misstatements using both
a balance sheet and income statement approach and contains guidance on correcting errors under the
dual approach, as well as providing transition guidance for correcting errors existing in prior
years. SAB 108 is effective for the first fiscal year ending after November 15, 2006, with early
application encouraged. The adoption of SAB 108 did not have a material impact on our results of
operations or financial position.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
We are exposed to market risks associated with foreign currency fluctuations and changes in
interest rates. A discussion of our market risk exposure in financial instruments follows.
Foreign Currency Exchange Rates
Because we operate in a number of countries throughout the world, we conduct a portion of our
business in currencies other than the U.S. dollar. The functional currency for our international
operations, other than our operations in the United Kingdom, is the U.S. dollar, but a portion of
the revenues from our foreign operations is paid in foreign currencies. The effects of foreign
currency fluctuations are partly mitigated because local expenses of such foreign operations are
also generally denominated in the same currency. We continually monitor the currency exchange
risks associated with all contracts not denominated in the U.S. dollar. Any gains or losses
associated with such fluctuations have not been material.
We do not hold any foreign currency exchange forward contracts and/or currency options. We have
not made use of derivative financial instruments to manage risks associated with existing or
anticipated transactions. We do not hold derivatives for trading purposes or use derivatives with
complex features. Assets and liabilities of our subsidiary in the United Kingdom are translated at
current exchange rates, while income and expense are translated at average rates for the period.
Translation gains and losses are reported as the foreign currency translation component of
accumulated other comprehensive income in stockholders equity.
Interest Rates
At December 31, 2006, none of our long-term debt outstanding had variable interest rates, and we
had no interest rate risks at that time.
Equity Price Risk
In December 2006, we issued $400 million of 1.50% Senior Exchangeable Notes due 2026 in a private
offering to qualified institutional buyers. The notes are, subject to the occurence of specified
conditions, exchangeable for our common stock initially at an exchange price of $45.58 per share,
which would result in an aggregate of approximately 8.8 million shares of common stock being issued
upon exchange. We may redeem for cash all or any part of the notes on or after December 15, 2011
for 100% of the principal amount redeemed. The holders may require us to repurchase for cash all
or any portion of the notes on December 15, 2011, December 15, 2016 and
December 15, 2021 for 100% of the principal amount of notes to be purchased plus any accrued and
unpaid interest. The notes do not contain any restrictive financial covenants.
Each $1,000 of principal amount of the notes is initially exchangeable into 21.9414 shares of our
common stock, subject to adjustment upon the occurrence of specified events. Holders of the notes
may exchange their notes prior to maturity only if: (1) the price of our common stock reaches
$45.58 during certain periods of time specified in the notes; (2) specified corporate transactions
occur; (3) the notes have been called for redemption; or (4) the trading price of the notes falls
below a certain threshold. In addition, in the event of a fundamental change in our corporate
33
ownership or structure, the holders may require us to repurchase all or any portion of the notes
for 100% of the principal amount.
Concurrently with the issuance of the notes, we entered into agreements with affiliates of the
initial purchasers to purchase call options and sell warrants of our common stock. We may exercise
the call options at any time to acquire approximately 8.8 million shares of our common stock at a
strike price of $45.58 per share. The owners of the warrants may exercise their warrants to
purchase from us approximately 8.8 million shares of our common stock at a price of $59.42 per
share, subject to certain anti-dilution and other customary adjustments. The warrants may be
settled in cash, in shares or in a combination of cash and shares, at our option. We paid $96
million (exclusive of a $35.5 million tax benefit) to acquire the call options and received $60.4 million as a result of the sale of the warrants.
For additional discussion of the notes, see Managements Discussion and Analysis of Financial
Condition and Results of OperationsLiquidity and Capital Resources in Part II, Item 7 above.
Commodity Price Risk
Our revenues, profitability and future rate of growth partially depends upon the market prices of
oil and natural gas. Lower prices may also reduce the amount of oil and gas that can economically
be produced.
We use derivative commodity instruments to manage commodity price risks associated with future oil
production. We have not hedged any of our natural gas production. Our hedging contracts for a
portion of our oil production expired on August 31, 2006, and there are no outstanding contracts as
of December 31, 2006 or as of the date of this Form 10-K.
34
Item 8. Financial Statements and Supplementary Data
Managements Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over our
financial reporting. Our internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting and the preparation
of our financial statements for external purposes in accordance with generally accepted accounting
principles.
Our system of internal control over financial reporting includes policies and procedures that (i)
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions
are recorded as necessary to permit preparation of financial statements in accordance with
generally accepted accounting principles, and that our receipts and expenditures are being made
only in accordance with authorizations of our management and directors; and (iii) provide
reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of our assets that could have a material effect on the financial statements.
In assessing the effectiveness of our internal control over financial reporting as of December 31,
2006, we have excluded Warrior Energy Services Corporation, which we acquired on December 12, 2006.
Warrior Energy Services Corporations total assets were $451.8 million, or approximately 24% of
our total assets, as of December 31, 2006, and Warrior Energy Services Corporations total revenues
were $7.7 million, or approximately 1% of our total revenues, for the year ended December 31, 2006.
Our management, including our principal executive officer and principal financial officer,
performed an assessment of the effectiveness of our internal control over financial reporting as of
December 31, 2006 based upon criteria in Internal Control Integrated Framework, issued by the
Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, our
management determined that our internal control over financial reporting was effective as of
December 31, 2006.
Our managements assessment of the effectiveness of our internal control over financial reporting
as of December 31, 2006 has been audited by KPMG LLP, an independent registered public accounting
firm, as stated in their report which appears herein which expresses unqualified opinions on our
managements assessment and on the effectiveness of our internal control over financial reporting
as of December 31, 2006.
35
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Superior Energy Services, Inc.:
We have audited the accompanying consolidated balance sheets of Superior Energy Services, Inc. and
subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of
operations, changes in stockholders equity and cash flows for each of the years in the three-year
period ended December 31, 2006. In connection with our audit of the consolidated financial
statements, we also have audited the accompanying financial statement schedule, Valuation and
Qualifying Accounts, for the years ended December 31, 2006, 2005 and 2004. These consolidated
financial statements and financial statement schedule are the responsibility of the Companys
management. Our responsibility is to express an opinion on these consolidated financial statements
and financial statement schedule 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 consolidated financial statements referred to above present fairly, in all
material respects, the financial position of Superior Energy Services, Inc. and subsidiaries as of
December 31, 2006 and 2005, and the results of their operations and their cash flows for each of
the years in the three-year period ended December 31, 2006, in conformity with U.S. generally
accepted accounting principles. Also in our opinion, the related financial statement schedule,
when considered in relation to the basic consolidated financial statements taken as a whole,
presents fairly, in all material respects, the information set forth therein.
As discussed in note 3 to the consolidated financial statements, the Company changed its method of
accounting for share-based compensation.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the effectiveness of Superior Energy Services, Inc.s internal control over
financial reporting as of December 31, 2006, based on criteria established in Internal
ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO), and our report dated February 28, 2007 expressed an unqualified opinion on
managements assessment of, and the effective operation of, internal control over financial
reporting.
New Orleans, Louisiana
February 28, 2007
36
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Superior Energy Services, Inc.:
We have audited managements assessment, included in the accompanying Managements Report on
Internal Control over Financial Reporting, that Superior Energy Services, Inc. maintained
effective internal control over financial reporting as of December 31, 2006, based on criteria
established in Internal ControlIntegrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). Superior Energy Services, Inc.s management is
responsible for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting. Our responsibility is
to express an opinion on managements assessment and an opinion on the effectiveness of the
Companys 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, evaluating managements assessment, testing and evaluating the
design and operating effectiveness of internal control, 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 companys 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
companys 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 companys 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, managements assessment that Superior Energy Services, Inc. maintained effective
internal control over financial reporting as of December 31, 2006, is fairly stated, in all
material respects, based on criteria established in Internal ControlIntegrated Framework issued by
the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion,
Superior Energy Services, Inc. maintained, in all material respects, effective internal control
over financial reporting as of December 31, 2006, based on criteria established in Internal
ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO).
Superior Energy Services, Inc. acquired Warrior Energy Services Corporation on December 12, 2006,
and management excluded from its assessment of the effectiveness of Superior Energy Services,
Inc.s internal control over financial reporting as of December 31, 2006, Warrior Energy Services
Corporations internal control over financial reporting associated with total assets of $451.8
million, or approximately 24% of the Companys total assets, and total revenues of $7.7 million ,
or approximately 1% of the Companys total revenues included in the consolidated financial
statements of Superior Energy Services, Inc. and subsidiaries as of and for the year ended December
31, 2006. Our audit of internal control over financial reporting of Superior Energy Services, Inc.
also excluded an evaluation of the internal control over financial reporting of Warrior Energy
Services Corporation.
37
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the consolidated balance sheets of Superior Energy Services, Inc. and
subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of
operations, changes in stockholders equity, and cash flows for each of the years in the three-year
period ended December 31, 2006. Our report dated February 28, 2007 expressed an unqualified
opinion on those consolidated financial statements. Our report for the year ended December 31,
2006 refers to a change in the method of accounting for share-based payments.
New Orleans, Louisiana
February 28, 2007
38
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
December 31, 2006 and 2005
(in thousands, except share data)
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
38,970 |
|
|
$ |
54,457 |
|
Accounts receivable, net of allowance for doubtful accounts of $17,419 and
$11,569 at December 31, 2006 and 2005, respectively |
|
|
303,800 |
|
|
|
196,365 |
|
Income taxes receivable |
|
|
2,630 |
|
|
|
|
|
Current portion of notes receivable |
|
|
14,824 |
|
|
|
2,364 |
|
Prepaid insurance and other |
|
|
59,563 |
|
|
|
51,116 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets |
|
|
419,787 |
|
|
|
304,302 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net |
|
|
626,558 |
|
|
|
440,328 |
|
Oil and gas assets, net, under the successful efforts method of accounting |
|
|
177,670 |
|
|
|
94,634 |
|
Goodwill |
|
|
444,687 |
|
|
|
220,064 |
|
Notes receivable |
|
|
16,137 |
|
|
|
29,483 |
|
Equity-method investments |
|
|
64,603 |
|
|
|
953 |
|
Intangible and other long-term assets, net |
|
|
125,036 |
|
|
|
7,486 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
1,874,478 |
|
|
$ |
1,097,250 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
65,451 |
|
|
$ |
42,035 |
|
Accrued expenses |
|
|
141,684 |
|
|
|
69,926 |
|
Income taxes payable |
|
|
|
|
|
|
11,353 |
|
Fair value of commodity derivative instruments |
|
|
|
|
|
|
10,792 |
|
Current portion of decommissioning liabilities |
|
|
35,150 |
|
|
|
14,268 |
|
Current maturities of long-term debt |
|
|
810 |
|
|
|
810 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
243,095 |
|
|
|
149,184 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income taxes |
|
|
112,011 |
|
|
|
91,899 |
|
Decommissioning liabilities |
|
|
87,046 |
|
|
|
107,641 |
|
Long-term debt |
|
|
711,505 |
|
|
|
216,596 |
|
Other long-term liabilities |
|
|
10,133 |
|
|
|
7,556 |
|
Stockholders equity: |
|
|
|
|
|
|
|
|
Preferred stock of $0.01 par value. Authorized, 5,000,000 shares; none issued |
|
|
|
|
|
|
|
|
Common stock of $0.001 par value. Authorized, 125,000,000 shares; issued
and outstanding 80,617,337 and 79,499,927 shares at December 31, 2006
and 2005, respectively |
|
|
81 |
|
|
|
79 |
|
Additional paid in capital |
|
|
411,374 |
|
|
|
428,507 |
|
Accumulated other comprehensive income (loss), net |
|
|
10,288 |
|
|
|
(4,916 |
) |
Retained earnings |
|
|
288,945 |
|
|
|
100,704 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity |
|
|
710,688 |
|
|
|
524,374 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
1,874,478 |
|
|
$ |
1,097,250 |
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
39
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Operations
Years Ended December 31, 2006, 2005 and 2004
(in thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Oilfield service and rental revenues |
|
$ |
966,139 |
|
|
$ |
656,423 |
|
|
$ |
527,331 |
|
Oil and gas revenues |
|
|
127,682 |
|
|
|
78,911 |
|
|
|
37,008 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
1,093,821 |
|
|
|
735,334 |
|
|
|
564,339 |
|
|
|
|
|
|
|
|
|
|
|
Cost of oilfield services and rentals |
|
|
427,477 |
|
|
|
330,200 |
|
|
|
288,561 |
|
Cost of oil and gas sales |
|
|
70,028 |
|
|
|
45,804 |
|
|
|
21,547 |
|
|
|
|
|
|
|
|
|
|
|
Total cost of services, rentals and sales |
|
|
497,505 |
|
|
|
376,004 |
|
|
|
310,108 |
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion, amortization and accretion |
|
|
111,011 |
|
|
|
89,288 |
|
|
|
67,337 |
|
General and administrative expenses |
|
|
168,416 |
|
|
|
140,989 |
|
|
|
110,605 |
|
Reduction in value of assets |
|
|
|
|
|
|
6,994 |
|
|
|
|
|
Gain on sale of liftboats |
|
|
|
|
|
|
3,544 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations |
|
|
316,889 |
|
|
|
125,603 |
|
|
|
76,289 |
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net of amounts capitalized |
|
|
(22,950 |
) |
|
|
(21,862 |
) |
|
|
(22,476 |
) |
Interest income |
|
|
4,612 |
|
|
|
2,201 |
|
|
|
1,766 |
|
Loss on early extinguishment of debt |
|
|
(12,596 |
) |
|
|
|
|
|
|
|
|
Earnings from equity-method investments |
|
|
5,891 |
|
|
|
1,339 |
|
|
|
1,329 |
|
Reduction in value of equity-method investment |
|
|
|
|
|
|
(1,250 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
291,846 |
|
|
|
106,031 |
|
|
|
56,908 |
|
Income taxes |
|
|
103,605 |
|
|
|
38,172 |
|
|
|
21,056 |
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
188,241 |
|
|
$ |
67,859 |
|
|
$ |
35,852 |
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share |
|
$ |
2.36 |
|
|
$ |
0.87 |
|
|
$ |
0.48 |
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share |
|
$ |
2.32 |
|
|
$ |
0.85 |
|
|
$ |
0.47 |
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares used in computing
earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
79,801 |
|
|
|
78,321 |
|
|
|
74,896 |
|
Incremental common shares from stock options |
|
|
1,451 |
|
|
|
1,394 |
|
|
|
994 |
|
Incremental common shares from restricted stock units |
|
|
37 |
|
|
|
20 |
|
|
|
10 |
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
|
81,289 |
|
|
|
79,735 |
|
|
|
75,900 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
40
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Changes in Stockholders Equity
Years Ended December 31, 2006, 2005 and 2004
(in thousands, except share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
Retained |
|
|
|
|
|
|
Preferred |
|
|
|
|
|
|
Common |
|
|
|
|
|
|
Additional |
|
|
other |
|
|
earnings |
|
|
|
|
|
|
stock |
|
|
Preferred |
|
|
stock |
|
|
Common |
|
|
paid-in |
|
|
comprehensive |
|
|
(Accumulated |
|
|
|
|
|
|
shares |
|
|
stock |
|
|
shares |
|
|
stock |
|
|
capital |
|
|
income (loss), net |
|
|
deficit) |
|
|
Total |
|
Balances, December 31, 2003 |
|
|
|
|
|
$ |
|
|
|
|
74,099,081 |
|
|
$ |
74 |
|
|
$ |
370,798 |
|
|
$ |
264 |
|
|
$ |
(3,007 |
) |
|
$ |
368,129 |
|
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
35,852 |
|
|
|
35,852 |
|
Other
comprehensive income -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in fair value of hedging
positions, net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,661 |
) |
|
|
|
|
|
|
(1,661 |
) |
Foreign currency translation
adjustment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,281 |
|
|
|
|
|
|
|
4,281 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,620 |
|
|
|
35,852 |
|
|
|
38,472 |
|
Stock issued for cash |
|
|
|
|
|
|
|
|
|
|
11,151,121 |
|
|
|
12 |
|
|
|
130,253 |
|
|
|
|
|
|
|
|
|
|
|
130,265 |
|
Purchase and retirement of stock |
|
|
|
|
|
|
|
|
|
|
(9,696,627 |
) |
|
|
(10 |
) |
|
|
(113,428 |
) |
|
|
|
|
|
|
|
|
|
|
(113,438 |
) |
Grant of restricted stock units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
180 |
|
|
|
|
|
|
|
|
|
|
|
180 |
|
Issuance of shares in exchange
for restricted stock units |
|
|
|
|
|
|
|
|
|
|
9,783 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercise of stock options and
directors stock compensation |
|
|
|
|
|
|
|
|
|
|
1,202,945 |
|
|
|
1 |
|
|
|
8,295 |
|
|
|
|
|
|
|
|
|
|
|
8,296 |
|
Tax benefit from stock options |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,975 |
|
|
|
|
|
|
|
|
|
|
|
1,975 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances, December 31, 2004 |
|
|
|
|
|
|
|
|
|
|
76,766,303 |
|
|
|
77 |
|
|
|
398,073 |
|
|
|
2,884 |
|
|
|
32,845 |
|
|
|
433,879 |
|
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
67,859 |
|
|
|
67,859 |
|
Other comprehensive income - |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in fair value of hedging
positions, net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,138 |
) |
|
|
|
|
|
|
(2,662 |
) |
Foreign currency translation
adjustment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,662 |
) |
|
|
|
|
|
|
(5,138 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,800 |
) |
|
|
67,859 |
|
|
|
60,059 |
|
Grant of restricted stock units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
158 |
|
|
|
|
|
|
|
|
|
|
|
158 |
|
Grant of restricted stock |
|
|
|
|
|
|
|
|
|
|
24,000 |
|
|
|
|
|
|
|
178 |
|
|
|
|
|
|
|
|
|
|
|
178 |
|
Exercise of stock options |
|
|
|
|
|
|
|
|
|
|
2,709,624 |
|
|
|
2 |
|
|
|
18,157 |
|
|
|
|
|
|
|
|
|
|
|
18,159 |
|
Tax benefit from stock options |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,941 |
|
|
|
|
|
|
|
|
|
|
|
11,941 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances, December 31, 2005 |
|
|
|
|
|
$ |
|
|
|
|
79,499,927 |
|
|
$ |
79 |
|
|
$ |
428,507 |
|
|
$ |
(4,916 |
) |
|
$ |
100,704 |
|
|
$ |
524,374 |
|
See accompanying notes to consolidated financial statements.
41
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Changes in Stockholders Equity (Continued)
Years Ended December 31, 2006, 2005 and 2004
(in thousands, except share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
Preferred |
|
|
|
|
|
|
Common |
|
|
|
|
|
|
Additional |
|
|
other |
|
|
|
|
|
|
|
|
|
stock |
|
|
Preferred |
|
|
stock |
|
|
Common |
|
|
paid-in |
|
|
comprehensive |
|
|
Retained |
|
|
|
|
|
|
shares |
|
|
stock |
|
|
shares |
|
|
stock |
|
|
capital |
|
|
income (loss), net |
|
|
earnings |
|
|
Total |
|
Balances, December 31, 2005 |
|
|
|
|
|
$ |
|
|
|
|
79,499,927 |
|
|
$ |
79 |
|
|
$ |
428,507 |
|
|
$ |
(4,916 |
) |
|
$ |
100,704 |
|
|
$ |
524,374 |
|
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
188,241 |
|
|
|
188,241 |
|
Other comprehensive income -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in fair value of hedging
positions, net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,799 |
|
|
|
|
|
|
|
6,799 |
|
Foreign currency translation
adjustment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,405 |
|
|
|
|
|
|
|
8,405 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15,204 |
|
|
|
188,241 |
|
|
|
203,445 |
|
Grant of restricted stock units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
542 |
|
|
|
|
|
|
|
|
|
|
|
542 |
|
Grant of restricted stock, net of
forfeitures |
|
|
|
|
|
|
|
|
|
|
242,775 |
|
|
|
|
|
|
|
986 |
|
|
|
|
|
|
|
|
|
|
|
986 |
|
Exercise of stock options |
|
|
|
|
|
|
|
|
|
|
244,047 |
|
|
|
1 |
|
|
|
2,802 |
|
|
|
|
|
|
|
|
|
|
|
2,803 |
|
Tax benefit from stock options |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,429 |
|
|
|
|
|
|
|
|
|
|
|
1,429 |
|
Stock option compensation expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
847 |
|
|
|
|
|
|
|
|
|
|
|
847 |
|
Issuance of common stock in connection
with acquisition of Warrior Energy
Services Corporation |
|
|
|
|
|
|
|
|
|
|
5,369,888 |
|
|
|
5 |
|
|
|
136,336 |
|
|
|
|
|
|
|
|
|
|
|
136,341 |
|
Shares repurchased and retired |
|
|
|
|
|
|
|
|
|
|
(4,739,300 |
) |
|
|
(4 |
) |
|
|
(159,995 |
) |
|
|
|
|
|
|
|
|
|
|
(159,999 |
) |
Purchase of common stock call options
related to exchangeable notes,
net of tax benefit of $35,520 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(60,480 |
) |
|
|
|
|
|
|
|
|
|
|
(60,480 |
) |
Sale of common stock warrant related
to exchangeable notes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
60,400 |
|
|
|
|
|
|
|
|
|
|
|
60,400 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances, December 31, 2006 |
|
|
|
|
|
$ |
|
|
|
|
80,617,337 |
|
|
$ |
81 |
|
|
$ |
411,374 |
|
|
$ |
10,288 |
|
|
$ |
288,945 |
|
|
$ |
710,688 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
42
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Years Ended December 31, 2006, 2005 and 2004
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
188,241 |
|
|
$ |
67,859 |
|
|
$ |
35,852 |
|
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion, amortization and accretion |
|
|
111,011 |
|
|
|
89,288 |
|
|
|
67,337 |
|
Deferred income taxes |
|
|
15,663 |
|
|
|
442 |
|
|
|
15,234 |
|
Stock-based and performance share unit compensation expense |
|
|
6,159 |
|
|
|
1,404 |
|
|
|
|
|
Reduction in value of assets and equity-method investment |
|
|
|
|
|
|
8,244 |
|
|
|
|
|
Earnings from equity-method investments |
|
|
(5,891 |
) |
|
|
(1,339 |
) |
|
|
(1,329 |
) |
Write-off of debt acquisition costs |
|
|
2,817 |
|
|
|
|
|
|
|
|
|
Amortization of debt acquisition costs and note discount |
|
|
1,321 |
|
|
|
1,127 |
|
|
|
887 |
|
Gain on sale of liftboats |
|
|
|
|
|
|
(3,544 |
) |
|
|
|
|
Changes in operating assets and liabilities, net of acquisitions and dispositions: |
|
|
|
|
|
|
|
|
|
|
|
|
Receivables |
|
|
(88,298 |
) |
|
|
(32,095 |
) |
|
|
(35,279 |
) |
Other, net |
|
|
13,892 |
|
|
|
(11,598 |
) |
|
|
(9,346 |
) |
Accounts payable |
|
|
7,259 |
|
|
|
5,696 |
|
|
|
16,142 |
|
Accrued expenses |
|
|
43,379 |
|
|
|
15,530 |
|
|
|
13,866 |
|
Decommissioning liabilities |
|
|
(2,255 |
) |
|
|
(8,772 |
) |
|
|
(9,157 |
) |
Income taxes |
|
|
(13,084 |
) |
|
|
26,137 |
|
|
|
(2,876 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
280,214 |
|
|
|
158,379 |
|
|
|
91,331 |
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Payments for capital expenditures |
|
|
(242,936 |
) |
|
|
(125,166 |
) |
|
|
(74,125 |
) |
Acquisitions of businesses, net of cash acquired |
|
|
(239,339 |
) |
|
|
(6,435 |
) |
|
|
(24,361 |
) |
Acquisitions of oil and gas properties, net of cash acquired |
|
|
(46,631 |
) |
|
|
3,686 |
|
|
|
(10,676 |
) |
Cash proceeds from sale of subsidiary, net of cash sold |
|
|
18,343 |
|
|
|
|
|
|
|
|
|
Cash contributed to equity-method investment |
|
|
(57,781 |
) |
|
|
|
|
|
|
|
|
Cash proceeds from sale of equity-method investment |
|
|
|
|
|
|
12,489 |
|
|
|
|
|
Cash proceeds from sale of liftboats, net |
|
|
|
|
|
|
19,588 |
|
|
|
|
|
Other |
|
|
(13,634 |
) |
|
|
(1,097 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(581,978 |
) |
|
|
(96,935 |
) |
|
|
(109,162 |
) |
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from long-term debt |
|
|
695,467 |
|
|
|
|
|
|
|
|
|
Principal payments on long-term debt |
|
|
(200,810 |
) |
|
|
(39,310 |
) |
|
|
(13,713 |
) |
Payment of debt acquisition costs |
|
|
(18,357 |
) |
|
|
(439 |
) |
|
|
(60 |
) |
Purchase of common stock call options related to exchangeable notes |
|
|
(96,000 |
) |
|
|
|
|
|
|
|
|
Sale of common stock warrants related to exchangeable notes |
|
|
60,400 |
|
|
|
|
|
|
|
|
|
Proceeds from exercise of stock options |
|
|
2,803 |
|
|
|
18,161 |
|
|
|
10,271 |
|
Tax benefit from exercise of stock options |
|
|
1,429 |
|
|
|
|
|
|
|
|
|
Proceeds from issuance of stock |
|
|
|
|
|
|
|
|
|
|
130,265 |
|
Purchase and retirement of stock |
|
|
(159,999 |
) |
|
|
|
|
|
|
(113,438 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities |
|
|
284,933 |
|
|
|
(21,588 |
) |
|
|
13,325 |
|
|
|
|
|
|
|
|
|
|
|
Effect of exchange rate changes in cash |
|
|
1,344 |
|
|
|
(680 |
) |
|
|
(7 |
) |
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents |
|
|
(15,487 |
) |
|
|
39,176 |
|
|
|
(4,513 |
) |
Cash and cash equivalents at beginning of year |
|
|
54,457 |
|
|
|
15,281 |
|
|
|
19,794 |
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year |
|
$ |
38,970 |
|
|
$ |
54,457 |
|
|
$ |
15,281 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
43
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006, 2005 and 2004
(1) |
|
Summary of Significant Accounting Policies |
|
(a) |
|
Basis of Presentation |
|
|
|
|
The consolidated financial statements include the accounts of Superior Energy Services,
Inc. and subsidiaries (the Company). All significant intercompany accounts and
transactions are eliminated in consolidation. Certain previously reported amounts have
been reclassified to conform to the 2006 presentation. |
|
|
(b) |
|
Business |
|
|
|
|
The Company is a leading provider of specialized oilfield services and equipment focusing
on serving the production-related and drilling-related needs of oil and gas companies.
The Company provides most of the services, tools and liftboats necessary to maintain,
enhance and extend offshore producing wells, as well as plug and abandonment services at
the end of their life cycle. |
|
|
|
|
The Company also acquires oil and gas properties in order to provide additional
opportunities for its well intervention operations in the Gulf of Mexico. The Company
acquires and produces oil and gas properties, provides various production-related services
to the properties and decommissions and abandons the properties. |
|
|
(c) |
|
Use of Estimates |
|
|
|
|
The preparation of financial statements in conformity with accounting principles generally
accepted in the United States of America requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and disclosure of
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. |
|
|
(d) |
|
Major Customers and Concentration of Credit Risk |
|
|
|
|
A majority of the Companys business is conducted with major and independent oil and gas
exploration companies. The Company evaluates the financial strength of its customers and
provides allowances for probable credit losses when deemed necessary but does not require
collateral to support the customer receivables. |
|
|
|
|
The market for the Companys services and products is primarily the offshore and onshore
oil and gas industry in the United States and select international market areas. Oil and
gas companies make capital expenditures on exploration, drilling and production
operations. The level of these expenditures has been characterized by significant
volatility. |
|
|
|
|
The Company derives a large amount of revenue from a small number of major and independent
oil and gas companies. In 2006 and 2005, Shell accounted for approximately 12% and 10%,
respectively, of total revenue, primarily related to our oil and gas and rental tools
segments. No customer accounted for more than 10% of the Companys total revenue in 2004.
The Companys inability to continue to perform services for a number of large existing
customers, if not offset by sales to new or existing customers, could have a material
adverse effect on the Companys business and financial condition. |
44
|
(e) |
|
Cash Equivalents |
|
|
|
|
The Company considers all short-term investments with a maturity of 90 days or less to be
cash equivalents. |
|
|
(f) |
|
Accounts Receivable and Allowances |
|
|
|
|
Trade accounts receivables are recorded at the invoiced amount and do not bear interest.
The Company maintains allowances for estimated uncollectible receivables including bad
debts and other items. The allowance for doubtful accounts is based on the Companys best
estimate of the amount of probable uncollectible amounts in existing accounts receivable.
The Company determines the allowance based on historical write-off experience and specific
identification. |
|
|
(g) |
|
Prepaid Insurance and Other |
|
|
|
|
Prepaid insurance and other includes approximately $13.6 million and $23.9 million in
insurance receivables at December 31, 2006 and 2005, respectively. The December 31, 2006
and 2005 balances are primarily due to the impact of Hurricanes Katrina and Rita on our
oil and gas properties, as well as our equipment. The insurance deductibles on Hurricanes
Katrina and Rita of approximately $1 million were expensed during 2005. All amounts not
expected to be reimbursed by insurance are expensed as incurred. |
|
|
(h) |
|
Property, Plant and Equipment |
|
|
|
|
Property, plant and equipment are stated at cost, except for assets acquired using
purchase accounting, which are recorded at fair value as of the date of acquisition. With
the exception of the Companys liftboats, derrick barge and oil and gas assets,
depreciation is computed using the straight-line method over the estimated useful lives of
the related assets as follows: |
|
|
|
Buildings and improvements
|
|
5 to 40 years |
Marine vessels and equipment
|
|
5 to 25 years |
Machinery and equipment
|
|
5 to 20 years |
Automobiles, trucks, tractors and trailers
|
|
2 to 10 years |
Furniture and fixtures
|
|
3 to 10 years |
The Companys liftboats and derrick barge are depreciated using the units-of-production
method based on the utilization of the vessels and are subject to a minimum amount of
annual depreciation. The Companys oil and gas producing assets are depleted using the
units-of-production method based on applicable quantities of oil and gas produced. The
units-of-production method is used for these assets because depreciation and depletion
occur primarily through use rather than through the passage of time.
The Company capitalizes interest on the cost of major capital projects during the active
construction period. Capitalized interest is added to the cost of the underlying assets
and is amortized over the useful lives of the assets. For 2006 and 2005, the Company
capitalized approximately $924,000 and $456,000, respectively, of interest for various
capital projects. There was no interest capitalized during 2004.
Long-lived assets and certain identifiable intangibles are reviewed for impairment
whenever events or changes in circumstances indicate that the carrying amount of an asset
may not be recoverable. Recoverability of assets to be held and used is measured by a
comparison of the carrying amount of an asset to future net cash flows expected to be
generated by the assets. If such assets are considered to be impaired, the impairment to
be recognized is measured by the amount by which the carrying amount of the assets exceeds
the fair value. Assets are grouped by subsidiary or division for the impairment testing,
except for liftboats which are grouped together by size. Assets to be disposed of are
reported at the lower of the carrying amount or fair value less costs to sell.
45
The Companys subsidiary, SPN Resources, LLC, acquires oil and natural gas properties and
assumes the related decommissioning liabilities. The Company follows the successful
efforts method of accounting for its investment in oil and natural gas properties. Under
the successful efforts method, the costs of successful exploratory wells and leases
containing productive reserves are capitalized. Costs incurred to drill and equip
developmental wells, including unsuccessful development wells are capitalized. Other
costs such as geological and geophysical costs and the drilling costs of unsuccessful
exploratory wells are expensed. SPN Resources property purchases are recorded
at the value exchanged at closing, combined with an estimate of its proportionate share of
the decommissioning liability assumed in the purchase. 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 units-of-production basis based on the
estimated remaining equivalent proved oil and gas reserves of each field. Well costs are
depleted on a units-of-production basis based on the estimated remaining equivalent proved
developed oil and gas reserves of each field.
Oil and gas properties are assessed for impairment in value on a field-by-field basis
whenever impairment indicators become evident. The Company uses its current estimate of
future revenues and operating expenses to test the capitalized costs for impairment. In
the event net undiscounted cash flows are less than the carrying value, an impairment loss
is recorded based on the present value of expected future net cash flows over the economic
lives of the reserves.
|
(i) |
|
Goodwill |
|
|
|
|
The Company accounts for goodwill and other intangible assets in accordance with Statement
of Financial Accounting Standards No. 142 (FAS No. 142), Goodwill and Other Intangible
Assets. FAS No. 142 requires that goodwill as well as other intangible assets with
indefinite lives no longer be amortized, but instead tested annually for impairment. To
test for impairment, the Company identifies its reporting units (which are consistent with
the Companys reportable segments) and determines the carrying value of each reporting
unit by assigning the assets and liabilities, including goodwill and intangible assets, to
the reporting units. The Company then estimates the fair value of each reporting unit and
compares it to the reporting units carrying value. Based on this test, the fair value of
the reporting units exceeded the carrying amount. No impairment loss was recognized in
the years ended December 31, 2006, 2005 or 2004 under this method. However, in 2005 the
Company reduced the value of goodwill by approximately $3.8 million to approximate the
sales price of its environmental subsidiary, which was sold in 2006 (see notes 4 and 11).
Goodwill increased by approximately $224.2 million in 2006 as a result of the Companys
business acquisitions including the acquisition of Warrior Energy Services Corporation.
Goodwill increased in 2006 by approximately $3.2 million as the result of changes in
foreign currency exchange rates and decreased by approximately $2.8 million as the result
of the sale of the Companys environmental subsidiary. Goodwill has been allocated to the
Companys reportable segments as follows: $285.3 million to the well intervention
segment; $148.2 million to the rental tools segment; and $11.2 million to the marine
segment. |
|
|
(j) |
|
Notes Receivable |
|
|
|
|
Notes receivable consist of commitments from the sellers of oil and gas properties towards
the abandonment of the acquired properties. Pursuant to the agreement with the sellers,
the Company will invoice the sellers agreed upon amounts at the completion of certain
decommissioning activities. These receivables are recorded at present value, and the
related discounts are amortized to interest income, based on the expected timing of the
decommissioning activities. |
|
|
(k) |
|
Intangible and Other Long-Term Assets |
|
|
|
|
Intangible and other long-term assets consist of the following at December 31, 2006 and
2005 (amounts in thousands): |
46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006 |
|
|
December 31, 2005 |
|
|
|
Gross |
|
|
Accumulated |
|
|
Net |
|
|
Gross |
|
|
Accumulated |
|
|
Net |
|
|
|
Amount |
|
|
Amortization |
|
|
Balance |
|
|
Amount |
|
|
Amortization |
|
|
Balance |
|
Customer relationships |
|
$ |
88,360 |
|
|
$ |
(451 |
) |
|
$ |
87,909 |
|
|
$ |
160 |
|
|
$ |
(98 |
) |
|
$ |
62 |
|
Tradenames |
|
|
12,788 |
|
|
|
(116 |
) |
|
|
12,672 |
|
|
|
88 |
|
|
|
(57 |
) |
|
|
31 |
|
Non-compete agreements |
|
|
500 |
|
|
|
(70 |
) |
|
|
430 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt acquisition costs |
|
|
19,736 |
|
|
|
(301 |
) |
|
|
19,435 |
|
|
|
9,623 |
|
|
|
(4,643 |
) |
|
|
4,980 |
|
Deferred compensation
plan assets |
|
|
4,265 |
|
|
|
|
|
|
|
4,265 |
|
|
|
1,410 |
|
|
|
|
|
|
|
1,410 |
|
Other |
|
|
444 |
|
|
|
(119 |
) |
|
|
325 |
|
|
|
1,772 |
|
|
|
(769 |
) |
|
|
1,003 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
126,093 |
|
|
$ |
(1,057 |
) |
|
$ |
125,036 |
|
|
$ |
13,053 |
|
|
$ |
(5,567 |
) |
|
$ |
7,486 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer relationships, tradenames, and non-compete agreements are amortized using
the straight-line method over their estimated useful lives of 15 years, 20 years, and 2
years, respectively. Debt acquisition costs are amortized primarily using the effective
interest method over the life of the related debt agreements ranging from 5 to 25 years.
Amortization expense was approximately $0.6 million. $0.3 million and $0.3 million for the
years ended December 31, 2006, 2005 and 2004, respectively. Estimated annual amortization
will be approximately $7 million for each of the next five years, excluding the effects of
any acquisitions or disposition subsequent to December 31, 2006.
|
(l) |
|
Decommissioning Liability |
|
|
|
|
The Company records estimated future decommissioning liabilities related to its oil and
gas producing properties pursuant to the provisions of Statement of Financial Accounting
Standards No. 143 (FAS No. 143), Accounting for Asset Retirement Obligations. FAS No.
143 requires entities to record the fair value of a liability at estimated present value
for an asset retirement obligation (decommissioning liabilities) in the period in which it
is incurred with a corresponding increase in the carrying amount of the related long-lived
asset. Subsequent to initial measurement, the decommissioning liability is required to be
accreted each period to present value. The Companys decommissioning liabilities consist
of costs related to the plugging of wells, the removal of facilities and equipment and
site restoration on oil and gas properties. |
|
|
|
|
The Company estimates the cost that would be incurred if it contracted an unaffiliated
third party to plug and abandon wells, abandon the pipelines, decommission and remove the
platforms and pipelines and clear the sites of its oil and gas properties, and uses that
estimate to record its proportionate share of the decommissioning liability. In
estimating the decommissioning liability, the Company performs detailed estimating
procedures, analysis and engineering studies. Whenever practical, the Company utilizes
its own equipment and labor services to perform well abandonment and decommissioning work.
When the Company performs these services, 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
abandoned. The recorded liability is first reduced by all cash expenses incurred to
abandon and decommission the property. If the recorded liability exceeds (or is less
than) the Companys incurred costs, then the difference is reported as income (or loss)
within revenue during the period in which the work is performed. The Company reviews the
adequacy of its decommissioning liability whenever indicators suggest that the estimated
cash flows needed to satisfy the liability have changed materially. The timing and
amounts of these cash flows are estimates, and changes to these estimates may result in
additional (or decreased) liabilities recorded, which in turn would increase (or decrease)
the carrying values of the related oil and gas properties. |
|
|
|
|
The following table summarizes the activity for the Companys decommissioning liability
for the twelve months ended December 31, 2006, 2005 and 2004 (amounts in thousands): |
47
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
Decommissioning liabilities, at beginning of period |
|
$ |
121,909 |
|
|
$ |
114,018 |
|
Liabilities acquired and incurred |
|
|
3,554 |
|
|
|
11,494 |
|
Liabilities settled |
|
|
(2,255 |
) |
|
|
(8,772 |
) |
Accretion |
|
|
4,866 |
|
|
|
4,476 |
|
Revision in estimated liabilities |
|
|
(5,878 |
) |
|
|
693 |
|
|
|
|
|
|
|
|
Total |
|
|
122,196 |
|
|
|
121,909 |
|
Current portion of decommissioning liabilities |
|
|
35,150 |
|
|
|
14,268 |
|
|
|
|
|
|
|
|
Decommissioning liabilities, at end of period |
|
$ |
87,046 |
|
|
$ |
107,641 |
|
|
|
|
|
|
|
|
|
(m) |
|
Revenue Recognition |
|
|
|
|
Revenue is recognized when services or equipment are provided. The Company contracts for
marine, well intervention and environmental projects either on a day rate or turnkey
basis, with a majority of its projects conducted on a day rate basis. The Companys
rental tools are rented on a day rate basis, and revenue from the sale of equipment is
recognized when the equipment is shipped. Reimbursements from customers for the cost of
rental tools that are damaged or lost down-hole are reflected as revenue at the time of
the incident. The Company recognizes oil and gas revenue from its interests in producing
wells as oil and natural gas is sold from those wells. The Company is accounting for the
revenues and related costs on its contract to construct a derrick barge for a third party
on the percentage-of-completion method utilizing engineering estimates and construction
progress (see note 7). |
|
|
(n) |
|
Income Taxes |
|
|
|
|
The Company provides for income taxes in accordance with Statement of Financial Accounting
Standards No. 109 (FAS No. 109), Accounting for Income Taxes. FAS No. 109 requires an
asset and liability approach for financial accounting and reporting for income taxes.
Deferred income taxes reflect the impact of temporary differences between amounts of
assets and liabilities for financial reporting purposes and such amounts as measured by
tax laws. |
|
|
(o) |
|
Earnings per Share |
|
|
|
|
Basic earnings per share is computed by dividing income available to common stockholders
by the weighted average number of common shares outstanding during the period. Diluted
earnings per share is computed in the same manner as basic earnings per share except that
the denominator is increased to include the number of additional common shares that could
have been outstanding assuming the exercise of stock options and restricted stock units
and the potential shares that would have a dilutive effect on earnings per share. |
|
|
(p) |
|
Financial Instruments |
|
|
|
|
The fair value of the Companys financial instruments of cash equivalents, accounts
receivable and current maturities of long-term debt approximates their carrying amounts.
The fair value of the Companys long-term debt is approximately
$711.6 million at December
31, 2006. |
|
|
(q) |
|
Foreign Currency |
|
|
|
|
The functional currency for the Companys United Kingdom subsidiary is the British pound,
and its financial statements are measured in British pounds. The assets and liabilities
are translated to U.S. dollars at currency exchange rates as of the balance sheet date,
and the revenues and expenses are
translated at the average currency exchange rates for the period. The aggregate effect of
translation |
48
|
|
|
adjustments are reported as accumulated other comprehensive income (loss) in
the Companys stockholders equity. |
|
|
|
|
The functional currency for the Companys other foreign subsidiaries is the U.S. dollar.
The financial statements of these subsidiaries are remeasured into U.S. dollars using the
historical exchange rate for most of the long-term assets and liabilities and the balance
sheet date exchange rate for most of the current assets and liabilities. An average
exchange rate is used for each period for revenues and expenses. These transaction gains
and losses, as well as any other transactions in a currency other than the functional
currency, are included in general and administrative expenses in the consolidated
statements of operations in the period in which the currency exchange rates change. The
Company recorded approximately $0.8 million, $(0.2) million and $0.4 million of these
transaction (gains) losses included in general and administrative expenses in the years
ended December 31, 2006, 2005 and 2004, respectively. |
|
|
(r) |
|
Stock Based Compensation |
|
|
|
|
Effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards
No. 123(R) (FAS No. 123R), Share-Based Payment (as amended) which requires that
compensation costs relating to share-based payment transactions be recognized in the
financial statements. The cost is measured at the grant date, based on the calculated
fair value of the award, and is recognized as an expense over the employees requisite
service period (generally the vesting period of the equity award). The Company is using
the modified prospective application method and, accordingly, financial statement amounts
for prior periods presented in these financial statements have not been restated to
reflect the fair value method of recognizing compensation costs relating to non-qualified
stock options. See note 3 regarding the Companys adoption of FAS No. 123(R). |
|
|
|
|
Prior to January 1, 2006, the Company followed the disclosure-only provisions of Statement
of Financial Accounting Standards No. 123 (FAS No. 123), Accounting for Stock-Based
Compensation using the measurement principles prescribed in Accounting Principles Boards
Opinion No. 25, Accounting for Stock Issued to Employees. No stock-based compensation
costs were recognized for stock options in net income prior to January 1, 2006, as all
options granted had an exercise price equal to the market value of the underlying common
stock on the date of the grant. Stock compensation costs from the grant of restricted
stock and restricted stock units were expensed as incurred. |
|
|
(s) |
|
Hedging Activities |
|
|
|
|
The Company entered into hedging transactions in 2004 that expired on August 31, 2006 to
secure a commodity price for a portion of its oil production and reduce its exposure to
oil price fluctuations. The Company does not enter into derivative transactions for
trading purposes. The Company used financially-settled crude oil swaps and zero-cost
collars that provided floor and ceiling prices with varying upside price participation.
The Companys swaps and zero-cost collars were designated and accounted for as cash flow
hedges. The Company has not hedged any of its natural gas production. The Company
recognized the fair value of all derivative instruments as assets or liabilities on the
balance sheet. Changes in the fair value of cash flow hedges, to the extent the hedge was
effective, were recognized in other comprehensive income until the hedged item was settled
and recorded in oil and gas revenues. For the years ended December 31, 2006, 2005 and
2004, hedging settlement payments reduced oil and gas revenues by approximately $13.8
million, $10.2 million and $1.6 million, respectively. The Company did not record any
material gains or losses due to hedge ineffectiveness for these periods. |
|
|
(t) |
|
Other Comprehensive Income (Loss) |
|
|
|
|
The following table reconciles the change in accumulated other comprehensive income (loss)
for the years ended December 31, 2006 and 2005 (amounts in thousands): |
49
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
Accumulated other comprehensive (loss) income, net,
December 31, 2005 and 2004, respectively |
|
$ |
(4,916 |
) |
|
$ |
2,884 |
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss), net of tax: |
|
|
|
|
|
|
|
|
Hedging activities: |
|
|
|
|
|
|
|
|
Reclassification adjustment for settled contracts,
net of tax of $5,124 in 2006 and $3,656 in 2005 |
|
|
8,726 |
|
|
|
6,499 |
|
Changes in fair value of outstanding hedging positions,
net of tax of ($1,131) in 2006 and ($6,545) in 2005 |
|
|
(1,927 |
) |
|
|
(11,637 |
) |
Foreign currency translation adjustment |
|
|
8,405 |
|
|
|
(2,662 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive income (loss) |
|
|
15,204 |
|
|
|
(7,800 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive income (loss), net,
December 31, 2006 and 2005, respectively |
|
$ |
10,288 |
|
|
$ |
(4,916 |
) |
|
|
|
|
|
|
|
(2) |
|
Supplemental Cash Flow Information |
The following table includes the Companys supplemental cash flow information for the years ended
December 31, 2006, 2005 and 2004 (amounts in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Cash paid for interest |
|
$ |
32,295 |
|
|
$ |
21,152 |
|
|
$ |
23,320 |
|
|
|
|
|
|
|
|
|
|
|
Cash paid for income taxes |
|
$ |
100,431 |
|
|
$ |
10,789 |
|
|
$ |
7,360 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Details of business acquisitions: |
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of assets |
|
$ |
460,771 |
|
|
$ |
6,627 |
|
|
$ |
25,614 |
|
Fair value of liabilities |
|
|
(76,887 |
) |
|
|
(31 |
) |
|
|
(1,158 |
) |
Common stock issued |
|
|
(136,341 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid |
|
|
247,543 |
|
|
|
6,596 |
|
|
|
24,456 |
|
Less cash acquired |
|
|
(8,204 |
) |
|
|
(163 |
) |
|
|
(95 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash paid for acquisitions |
|
$ |
239,339 |
|
|
$ |
6,433 |
|
|
$ |
24,361 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Details of oil and gas property acquisitions: |
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of assets |
|
$ |
50,350 |
|
|
$ |
11,494 |
|
|
$ |
97,792 |
|
Fair value of liabilities |
|
|
(3,719 |
) |
|
|
(11,494 |
) |
|
|
(82,107 |
) |
|
|
|
|
|
|
|
|
|
|
Cash paid |
|
|
46,631 |
|
|
|
|
|
|
|
15,685 |
|
Less cash acquired |
|
|
|
|
|
|
(3,686 |
) |
|
|
(5,009 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash paid for acquisitions |
|
$ |
46,631 |
|
|
$ |
(3,686 |
) |
|
$ |
10,676 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash investing activity: |
|
|
|
|
|
|
|
|
|
|
|
|
Receivable from sale of affiliate |
|
$ |
|
|
|
$ |
1,305 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional consideration payable
on acquisitions |
|
$ |
|
|
|
$ |
|
|
|
$ |
5,272 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash financing activity: |
|
|
|
|
|
|
|
|
|
|
|
|
Deferred tax asset on purchase of
common stock call options related to
exchangeable notes |
|
$ |
35,520 |
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
50
(3) Stock-Based and Long-Term Compensation
The Company maintains the 2005 Stock Incentive Plan, the 2002 Stock Incentive Plan, the 1999 Stock
Incentive Plan and the 1995 Stock Incentive Plan, as amended. These plans provide long-term
incentives to the Companys key employees, including officers and directors, consultants and
advisers (Eligible Participants). Under the 2005 Stock Incentive Plan, the 2002 Stock Incentive
Plan, the 1999 Stock Incentive Plan and the 1995 Stock Incentive Plan, the Company may grant
incentive stock options, non-qualified stock options, restricted stock, restricted stock units,
stock appreciation rights, other stock-based awards or any combination thereof to Eligible
Participants for up to 4,000,000 shares, 1,400,000 shares, 5,929,327 shares and 1,900,000 shares,
respectively, of the Companys common stock. The Compensation Committee of the Companys Board of
Directors establishes the term and the exercise price of any stock options granted under the plans,
provided the exercise price may not be less than the fair value of the common share on the date of
grant. All of the options which have been granted under the 1995 Stock Incentive Plan, the 1999
Stock Incentive Plan and the 2002 Stock Incentive Plan were fully-vested by December 31, 2006.
Stock Options
The Company has granted non-qualified stock options under its stock incentive plans. The options
generally vest in equal installments over three years and expire in ten years. Non-vested options
are generally forfeited upon termination of employment. On February 23, 2006, the Company granted
212,600 non-qualified stock options and on December 14, 2006, the Company granted 127,617
non-qualified stock options from its 2005 Stock Incentive Plan under these same terms.
Beginning January 1, 2006, the Company adopted FAS No. 123R and began recognizing compensation
expense for stock option grants based on the fair value at the date of grant using the
Black-Scholes-Merton option pricing model. With the adoption of FAS No. 123R, the Company has
contracted a third party to assist in the valuation of option grants. The Company uses historical
data, among other factors, to estimate the expected price volatility, the expected option life and
the expected forfeiture rate. The risk-free rate is based on the U.S. Treasury yield curve in
effect at the time of grant for the expected life of the option. The following table presents the
fair value of stock option grants made during the years ended December 31, 2006, 2005 and 2004 and
the related assumptions used to calculate the fair value:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
|
Actual |
|
|
Pro Forma |
|
|
Pro Forma |
|
Weighted-average fair value of grants |
|
$ |
13.02 |
|
|
$ |
7.47 |
|
|
$ |
6.22 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Black-Scholes-Merton Assumptions: |
|
|
|
|
|
|
|
|
|
|
|
|
Risk free interest rate |
|
|
4.57 |
% |
|
|
3.85 |
% |
|
|
4.28 |
% |
Expected life (years) |
|
|
5 |
|
|
|
6 |
|
|
|
5 |
|
Volatility |
|
|
44.36 |
% |
|
|
38.91 |
% |
|
|
65.22 |
% |
Dividend yield |
|
|
|
|
|
|
|
|
|
|
|
|
The Companys compensation expense related to stock options for the year ended December 31,
2006 was approximately $0.8 million, which is reflected in general and administrative expenses. No
compensation expense related to options was recorded during the years ended December 31, 2005 or
2004.
The pro forma data presented below show the effects of stock option costs had they been expensed in
prior periods (amounts are in thousands, except per share amounts):
51
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
2004 |
|
Net income, as reported |
|
$ |
67,859 |
|
|
$ |
35,852 |
|
Stock-based employee compensation
expense, net of tax |
|
|
(4,421 |
) |
|
|
(6,999 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma net income |
|
$ |
63,438 |
|
|
$ |
28,853 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share: |
|
|
|
|
|
|
|
|
Earnings, as reported |
|
$ |
0.87 |
|
|
$ |
0.48 |
|
Stock-based employee compensation
expense, net of tax |
|
|
(0.06 |
) |
|
|
(0.09 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma earnings per share |
|
$ |
0.81 |
|
|
$ |
0.39 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share: |
|
|
|
|
|
|
|
|
Earnings, as reported |
|
$ |
0.85 |
|
|
$ |
0.47 |
|
Stock-based employee compensation
expense, net of tax |
|
|
(0.06 |
) |
|
|
(0.09 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma earnings per share |
|
$ |
0.79 |
|
|
$ |
0.38 |
|
|
|
|
|
|
|
|
The following table summarizes stock option activity for the years ended December 31, 2006,
2005 and 2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
Average |
|
|
Aggregate |
|
|
|
|
|
|
|
Average |
|
|
Remaining |
|
|
Intrinsic |
|
|
|
Number of |
|
|
Option |
|
|
Contractual |
|
|
Value (in |
|
|
|
Options |
|
|
Price |
|
|
Term (in years) |
|
|
thousands) |
|
Outstanding at December 31, 2003 |
|
|
5,628,000 |
|
|
$ |
7.53 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted |
|
|
1,490,000 |
|
|
$ |
10.66 |
|
|
|
|
|
|
|
|
|
Exercised |
|
|
(1,196,060 |
) |
|
$ |
7.01 |
|
|
|
|
|
|
|
|
|
Forfeited |
|
|
(124,645 |
) |
|
$ |
8.14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2004 |
|
|
5,797,295 |
|
|
$ |
8.43 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted |
|
|
863,500 |
|
|
$ |
17.46 |
|
|
|
|
|
|
|
|
|
Exercised |
|
|
(2,709,624 |
) |
|
$ |
6.94 |
|
|
|
|
|
|
|
|
|
Forfeited |
|
|
(57,538 |
) |
|
$ |
10.23 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2005 |
|
|
3,893,633 |
|
|
$ |
11.44 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted |
|
|
340,217 |
|
|
$ |
29.00 |
|
|
|
|
|
|
|
|
|
Exercised |
|
|
(244,047 |
) |
|
$ |
11.48 |
|
|
|
|
|
|
|
|
|
Forfeited |
|
|
(18,917 |
) |
|
$ |
16.85 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2006 |
|
|
3,970,886 |
|
|
$ |
12.91 |
|
|
|
6.9 |
|
|
$ |
78,880 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at December 31, 2006 |
|
|
3,630,669 |
|
|
$ |
11.40 |
|
|
|
6.7 |
|
|
$ |
77,246 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options expected to vest |
|
|
340,217 |
|
|
$ |
13.02 |
|
|
|
9.5 |
|
|
$ |
1,635 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The aggregate intrinsic value in the table above represents the total pre-tax intrinsic value (the
difference between the Companys closing stock price on December 31, 2006 and the option price,
multiplied by the number of in-the-money options) that would have been received by the option
holders if all the options had been exercised on
52
December 31, 2006. The Company expects all of its
remaining non-vested options to vest as they are primarily held by its officers and senior
managers.
The total intrinsic value of options exercised during the year ended December 31, 2006 (the
difference between the stock price upon exercise and the option price) was approximately $4.0
million. The Company received approximately $2.8 million during the year ended December 31, 2006
from employee stock option exercises. In accordance with FAS No. 123R, the Company has reported
the tax benefits of approximately $1.4 million from the exercise of stock options for the year
ended December 31, 2006 as financing cash flows. Prior to implementation of FAS No. 123R, the
Company reported the tax benefits from the exercise of stock options of approximately $11.9 million
in operating cash flows for the year ended December 31, 2005.
A summary of information regarding stock options outstanding at December 31, 2006 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding |
|
Options Exercisable |
Range of |
|
|
|
|
|
Weighted Average |
|
Weighted |
|
|
|
|
|
Weighted |
Exercise |
|
|
|
|
|
Remaining |
|
Average |
|
|
|
|
|
Average |
Prices |
|
Shares |
|
Contractual Life |
|
Price |
|
Shares |
|
Price |
|
$ 4.75 - $ 5.75 |
|
|
24,500 |
|
|
2.1 years |
|
$ |
5.57 |
|
|
|
24,500 |
|
|
$ |
5.57 |
|
$ 7.31 - $ 8.79 |
|
|
678,797 |
|
|
5.0 years |
|
$ |
8.37 |
|
|
|
678,797 |
|
|
$ |
8.37 |
|
$ 9.10 - $ 9.90 |
|
|
716,372 |
|
|
4.9 years |
|
$ |
9.40 |
|
|
|
716,372 |
|
|
$ |
9.40 |
|
$10.36 - $10.90 |
|
|
1,430,000 |
|
|
7.6 years |
|
$ |
10.66 |
|
|
|
1,430,000 |
|
|
$ |
10.66 |
|
$12.45 - $17.46 |
|
|
781,000 |
|
|
8.4 years |
|
$ |
17.43 |
|
|
|
781,000 |
|
|
$ |
17.43 |
|
$24.90 - $25.00 |
|
|
212,600 |
|
|
9.1 years |
|
$ |
24.99 |
|
|
|
|
|
|
$ |
|
|
$35.60 - $35.70 |
|
|
127,617 |
|
|
10.0 years |
|
$ |
35.69 |
|
|
|
|
|
|
$ |
|
|
The following table summarizes non-vested stock option activity for the year ended December 31,
2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
Average |
|
|
|
Number of |
|
|
Grant-Date |
|
|
|
Options |
|
|
Fair Value |
|
Non-vested at December 31, 2005 |
|
|
133,912 |
|
|
$ |
3.63 |
|
Granted |
|
|
340,217 |
|
|
$ |
13.02 |
|
Vested |
|
|
(133,245 |
) |
|
$ |
3.64 |
|
Forfeited |
|
|
(667 |
) |
|
$ |
3.62 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-vested at December 31, 2006 |
|
|
340,217 |
|
|
$ |
13.02 |
|
|
|
|
|
|
|
|
As of December 31, 2006, there was approximately $3.7 million of unrecognized compensation expense
related to non-vested stock options outstanding. The Company expects to recognize approximately
$1.4 million, $1.5 million and $0.8 million of compensation expense during the years 2007, 2008 and
2009, respectively, for these non-vested stock options outstanding.
Restricted Stock
During the year ended December 31, 2006, the Company granted 247,975 shares of restricted stock to
its employees. These shares of restricted stock vest in equal annual installments over three
years. Non-vested shares are generally forfeited upon the termination of employment. Holders of
the shares of restricted stock are entitled to all rights of a shareholder of the Company with
respect to the restricted stock, including the right to vote the shares and receive all dividends
and other distributions declared thereon. Compensation expense associated with shares of
restricted stock is measured based on the grant-date fair value of our common stock and is
recognized on a straight-line basis over the vesting period. The Companys compensation expense
related to shares of restricted stock outstanding for the
53
years ended December 31, 2006 and 2005
was approximately $1.0 million and $0.2 million, respectively, which is reflected in general and
administrative expenses.
A summary of the status of the shares of restricted stock for the year ended December 31, 2006 is
presented in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
Number of |
|
|
Average Grant |
|
|
|
Shares |
|
|
Date Fair Value |
|
Non-vested at December 31, 2005 |
|
|
24,000 |
|
|
$ |
22.24 |
|
Granted |
|
|
247,975 |
|
|
$ |
31.19 |
|
Vested |
|
|
(9,000 |
) |
|
$ |
22.55 |
|
Forfeited |
|
|
(5,200 |
) |
|
$ |
24.99 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-vested at December 31, 2006 |
|
|
257,775 |
|
|
$ |
30.78 |
|
|
|
|
|
|
|
|
As of December 31, 2006, there was approximately $7.0 million of unrecognized compensation expense
related to non-vested restricted stock shares. The Company expects to recognize approximately $2.6
million, $2.5 million and $1.8 million during the years 2007, 2008 and 2009, respectively, for
these shares of non-vested restricted stock.
Restricted Stock Units
In May 2006, the Companys stockholders approved the Amended and Restated 2004 Directors Restricted
Stock Units Plan. The plan provides that each non-employee director is granted a number of
restricted stock units having an aggregate value of $100,000, with the exact number of units
determined by dividing $100,000 by the fair market value of the Companys common stock on the day
of the annual stockholders meeting or a pro rata amount if the appointment occurs subsequent to
the annual stockholders meeting. A restricted stock unit represents the right to receive from the
Company, within 30 days of the date the participant ceases to serve on the Board, one share of the
Companys common stock. As a result of this plan, 37,482 restricted stock units were outstanding
at December 31, 2006. The Companys expense related to restricted stock units for the year ended
December 31, 2006 and 2005 was approximately $0.9 million and $0.2 million, respectively, which is
reflected in general and administrative expenses.
A summary of the activity of restricted stock units for the year ended December 31, 2006 is
presented in the table below:
|
|
|
|
|
|
|
|
|
|
|
Number of |
|
|
Weighted |
|
|
|
Restricted |
|
|
Average Grant |
|
|
|
Stock Units |
|
|
Date Fair Value |
|
Outstanding at December 31, 2005 |
|
|
19,998 |
|
|
$ |
12.38 |
|
Granted |
|
|
17,484 |
|
|
$ |
30.98 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2006 |
|
|
37,482 |
|
|
$ |
21.06 |
|
|
|
|
|
|
|
|
Performance Share Units
The Company awards performance share units (PSUs) to its employees as part of the Companys
long-term incentive program. There is a three-year performance period associated with each PSU
grant date. The two performance measures applicable to all participants are the Companys return
on invested capital and total shareholder return relative to those of the Companys pre-defined
peer group. The PSUs provide for settlement in cash or up to 50% in equivalent value in the
Companys common stock, if the participant has met specified continued service requirements. At
December 31, 2006, there were 119,179 PSUs outstanding (31,128, 32,669 and 55,382 related to the
three-year performance periods ending December 31, 2007, 2008 and 2009, respectively). The
54
Companys compensation expense related to all outstanding PSUs for the years ended December 31,
2006 and 2005 was approximately $3.5 million and $1.0 million, respectively, which is reflected in
general and administrative expenses. At December 31, 2006, the Company has recorded a liability of
approximately $4.5 million for all outstanding PSUs which is reflected in accrued expenses.
(4) Acquisitions and Dispositions
On December 12, 2006, the Company acquired Warrior Energy Services Corporation (Warrior) for a
total purchase price of $374.1 million. The total consideration was comprised of cash payments of
$237.8 million (including acquisition costs and repayment of Warriors debt) and equity
consideration of $136.3 million (5,369,888 shares of common stock valued at $25.39 per share, the
average closing market price per share for the five trading day period beginning two trading days
before the merger announcement date of September 25, 2006). The acquisition has been accounted for
as a purchase, and the results of operations of Warrior have been included from the acquisition
date.
Warrior is an oil and gas services company that provides various well intervention services
including wireline, electric line, logging, perforating, mechanical services, pipe recovery, plug
and abandonment and hydraulic workover services. Warrior also provides various rental tools and
equipment to its market areas including drill pipe, handling tools and accessories, pressure
control equipment, fishing tools, stabilizers, power swivels, test pumps and hydraulic torque
wrenches. Warrior has 25 operating bases in 10 states with operations concentrated in the major
onshore and offshore oil and gas producing areas of the United States, including onshore in
Alabama, Arkansas, Colorado, Kansas, Louisiana, Mississippi, Montana, New Mexico, North Dakota,
Oklahoma, Texas, Utah and Wyoming and offshore in the Gulf of Mexico. The Company acquired Warrior
to further strengthen its well intervention and rental operations into these onshore locations.
The assets and liabilities were valued at their estimated fair value as of the date of acquisition.
The Company obtained a third party valuation to assist it in the assessment of the fair value of
Warriors assets and liabilities. The allocation of the purchase price and the valuation of the
assets and liabilities will be subject to refinement as the Company gathers additional information
with respect to income taxes, outstanding litigation and other items. The Company will have 12
months from the acquisition date to finalize the valuation of the assets and liabilities and any
changes to the initial valuation may result in a change to goodwill. The following table
summarizes the preliminary estimated fair values of the Warrior assets and liabilities acquired as
of the acquisition date (amounts in thousands):
|
|
|
|
|
ASSETS |
|
|
|
|
Current assets |
|
$ |
32,728 |
|
Property, plant and equipment |
|
|
98,386 |
|
Goodwill |
|
|
218,711 |
|
Intangible and other assets |
|
|
101,123 |
|
|
|
|
|
|
|
|
|
|
Total assets acquired |
|
$ |
450,948 |
|
|
|
|
|
|
|
|
|
|
LIABILITIES |
|
|
|
|
Current liabilities |
|
$ |
40,257 |
|
Deferred income taxes |
|
|
36,630 |
|
|
|
|
|
|
|
|
|
|
Total liabilities assumed |
|
|
76,887 |
|
|
|
|
|
|
|
|
|
|
Net assets acquired |
|
$ |
374,061 |
|
|
|
|
|
The intangible and other assets and the related estimated useful lives include: approximately $88.2
million of customer relationships with a 15 year life, $12.7 million of tradenames with a 20 year
life, and $0.2 million of non-compete agreements with a 2 year life. The goodwill was assigned to
the well intervention and rental segments of approximately $201.4 million and $17.3 million,
respectively.
In July 2006, Coldren Resources LP (Coldren Resources) completed the acquisition from Noble Energy,
Inc. (Noble) of substantially all of Nobles offshore Gulf of Mexico shallow water oil and gas
properties. The Companys wholly-owned subsidiary SPN Resources, LLC (SPN Resources), acquired a
40% interest in Coldren
55
Resources for an initial cash investment of $57.8 million. The Companys
investment in Coldren Resources is accounted for under the equity-method of accounting. Amounts
included in the pro forma information below represent the Companys 40% ownership interest in the
performance of the Noble properties prior to their acquisition by Coldren Resources in July 2006
and do not include general and administrative expenses associated with these oil and gas
properties.
In April 2006, SPN Resources acquired additional oil and gas properties through the acquisition of
five offshore Gulf of Mexico leases. Under the terms of the transaction, the Company acquired the
properties and assumed the related decommissioning liabilities. The Company paid cash in the
amount of $46.6 million and preliminarily recorded decommissioning liabilities of approximately
$3.7 million and oil and gas producing assets of approximately $50.3 million.
The Company made other business acquisitions, which were not significant on an individual basis,
requiring aggregate cash consideration of $9.8 million in 2006 and $1.3 million in 2005. The
Company sold its environmental subsidiary in the first quarter of 2006 for approximately $18.7
million in cash. Also, the Company acquired offshore Gulf of Mexico oil and gas properties and
assumed the related decommissioning liabilities in July 2005 for $3.7 million in cash received and
the sellers agreement to pay amounts as decommissioning activities are completed.
The following unaudited pro forma information for the years ended December 31, 2006 and 2005
presents a summary of the consolidated results of operations as if the business acquisitions and
disposition described above had occurred on January 1, 2005, with pro forma adjustments to give
effect to depreciation, depletion, and certain other adjustments, together with related income tax
effects (in thousands, except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
Revenues |
|
$ |
1,221,259 |
|
|
$ |
830,793 |
|
|
|
|
|
|
|
|
Net income |
|
$ |
206,286 |
|
|
$ |
116,858 |
|
|
|
|
|
|
|
|
Basic earnings per share |
|
$ |
2.57 |
|
|
$ |
1.48 |
|
|
|
|
|
|
|
|
Diluted earnings per share |
|
$ |
2.52 |
|
|
$ |
1.45 |
|
|
|
|
|
|
|
|
The above pro forma information is not necessarily indicative of the results of operations that
would have been achieved had the acquisitions and disposition been effected on January 1, 2005.
Several of the Companys prior business acquisitions require future payments if specific conditions
are met. As of December 31, 2006, the maximum additional consideration payable was approximately
$2.4 million, and will be determined and payable through 2008.
Subsequent Event
In January 2007, the Company acquired Duffy & McGovern Accommodations Services Limited (Duffy &
McGovern) for approximately $47 million in cash consideration. Duffy & McGovern is a provider of
offshore accommodation rentals operating in most major deep water oil and gas territories with
major operations in Europe, Africa, the Americas and South East Asia. Duffy & McGovern has a
current working fleet of approximately 260 offshore accommodation units, which are certified for
deep water projects. The Company acquired Duffy & McGovern to further expand its rental tools
segment internationally. The acquisition will be accounted for as a purchase.
(5) Property, Plant and Equipment
A summary of property, plant and equipment at December 31, 2006 and 2005 (in thousands) is as
follows:
56
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
Buildings and improvements and leasehold
improvements |
|
$ |
53,240 |
|
|
$ |
58,567 |
|
Marine vessels and equipment |
|
|
217,422 |
|
|
|
177,047 |
|
Machinery and equipment |
|
|
561,570 |
|
|
|
394,582 |
|
Automobiles, trucks, tractors and trailers |
|
|
23,829 |
|
|
|
9,428 |
|
Furniture and fixtures |
|
|
17,274 |
|
|
|
13,440 |
|
Construction-in-progress |
|
|
48,274 |
|
|
|
19,054 |
|
Land |
|
|
7,328 |
|
|
|
6,581 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
928,937 |
|
|
|
678,699 |
|
Accumulated depreciation |
|
|
(302,379 |
) |
|
|
(238,371 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net |
|
$ |
626,558 |
|
|
$ |
440,328 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas assets |
|
|
229,329 |
|
|
|
119,986 |
|
Accumulated depletion |
|
|
(51,659 |
) |
|
|
(25,352 |
) |
|
|
|
|
|
|
|
Oil and gas assets, net, under the successful efforts
method of accounting |
|
$ |
177,670 |
|
|
$ |
94,634 |
|
|
|
|
|
|
|
|
The Company has approximately $11 million and $16 million of leasehold improvements at December 31,
2006 and 2005, respectively. These leasehold improvements are depreciated over the shorter of the
life of the asset or the life of the lease using the straight-line method. Depreciation expense
(excluding depletion, amortization and accretion) was approximately $79.3 million, $68.6 million
and $57.1 million for the years ended December 31, 2006, 2005 and 2004, respectively.
(6) Equity-Method Investments
Investments in entities that are not controlled by the Company, but where the Company has the
ability to exercise influence over the operations are accounted for using the equity-method. The
Companys share of the income or losses of these entities is reflected as earnings from
equity-method investments on its Consolidated Statements of Operations.
In May 2006, SPN Resources acquired a 40% interest in Coldren Resources. In July 2006, Coldren
Resources completed its acquisition of the oil and gas properties from Noble. The Company made
total cash contributions for its equity-method investment of approximately $57.8 million through
December 31, 2006. The Companys equity-method investment balance in Coldren Resources is
approximately $63.6 million at December 31, 2006, and the earnings from the equity-method
investment in Coldren Resources is approximately $5.8 million for the year ended December 31, 2006.
Coldren Resources had total proved reserves of approximately 4,940 Mbbls of oil and 88,837 Mmcf of
gas at December 31, 2006. Coldren Resources standardized measure of discounted future net cash
flows applicable to proved oil and natural gas reserves is approximately $370.9 million at December
31, 2006.
The Company provides operating and administrative support services to Coldren Resources and
receives reimbursement for general and administrative and direct expenses incurred on behalf of
Coldren Resources. The Company also, where possible and at competitive rates, provides its
products and services to assist Coldren Resources in producing and developing its oil and gas
properties. At December 31, 2006, the Company had receivables of approximately $3.0 million due
from Coldren Resources. The Company reduced its general and administrative expenses by
approximately $1.7 million by the reimbursements due from Coldren Resources. The Company also
recorded revenue of approximately $1.4 million from Coldren Resources in 2006. The Company reduces
its revenue and its investment in Coldren Resources for its 40% ownership when products and
services are provided to and capitalized by Coldren Resources. The Company records these amounts
in revenue as Coldren Resources records the related depreciation and depletion expenses. The
Company recorded a net reduction to revenue and its investment in Coldren Resources of
approximately $23,000 for the year ended December 31, 2006 as a result of these adjustments.
57
Summarized balance sheet and statement of operations information for Coldren Resources is as
follows (amounts in thousands):
Balance Sheet
|
|
|
|
|
|
|
December 31, |
|
|
|
2006 |
|
Current assets |
|
$ |
176,860 |
|
Property, plant and equipment, net |
|
|
522,941 |
|
Other long-term assets |
|
|
23,135 |
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
722,936 |
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
27,922 |
|
Decommissioning and other long-term
liabilities |
|
|
89,610 |
|
Long-term debt |
|
|
432,697 |
|
|
|
|
|
|
|
|
|
|
Total liabilities |
|
|
550,229 |
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive income, net |
|
|
13,861 |
|
Partners capital |
|
|
158,846 |
|
|
|
|
|
|
|
|
|
|
Total capital |
|
|
172,707 |
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners capital |
|
$ |
722,936 |
|
|
|
|
|
Statement of Operations
|
|
|
|
|
|
|
Year Ended |
|
|
|
December 31, |
|
|
|
2006 |
|
Revenues |
|
$ |
118,650 |
|
Lease operating expenses |
|
|
(30,176 |
) |
Depreciation, depletion, amortization
and accretion |
|
|
(62,981 |
) |
General and administrative expenses |
|
|
(6,535 |
) |
Interest expense |
|
|
(21,391 |
) |
Interest income |
|
|
1,785 |
|
Gain on derivatives |
|
|
15,321 |
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
14,673 |
|
|
|
|
|
Also
included in equity-method investments at December 31, 2006 and
2005 is approximately a $1.0 million investment for a 50% ownership in a company that owns an airplane. Earnings from this equity-method
investment were approximately $23,000, $9,000 and $264,000 for the years ended December 31, 2006,
2005 and 2004, respectively. The Company recorded approximately $227,000, $195,000 and $178,000 in
expense to lease the airplane from this company for the years ended December 31, 2006, 2005 and
2004, respectively.
In November 2005, the Company sold its equity-method investment in a rental tool company. The
Company received $12.5 million in cash as a result of the sale and has receivables of approximately
$1.1 million at December 31, 2006 for the remaining proceeds to be distributed, of which $0.9
million were received in January 2007. The Company reduced the value of this investment by
approximately $1.3 million during 2005 in anticipation of this sale.
58
(7) Construction Contract
In July 2006, the Company contracted to construct a derrick barge that will be sold to a third
party for approximately $54 million. The contract to construct the derrick barge to the customers
specifications is accounted for on the percentage-of-completion method utilizing engineering
estimates and construction progress. This methodology requires the Company to make estimates
regarding the progress against the project schedule and estimated completion date, both of which
impact the amount of revenue and gross margin the Company recognizes in each reporting period.
Contract costs primarily include sub-contract and program management costs. Provisions for any
anticipated losses will be recorded in full when such losses become evident. Included in accrued
expenses at December 31, 2006 is approximately $12.3 million of billings in excess of costs and
estimated earnings related to this contract.
(8) Long-Term Debt
The Companys long-term debt as of December 31, 2006 and 2005 consisted of the following (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
Senior Notes interest payable semiannually at 6.875%,
due June 2014 |
|
$ |
300,000 |
|
|
$ |
|
|
Discount on 6.875% Senior Notes |
|
|
(4,281 |
) |
|
|
|
|
Senior Notes interest payable semiannually at 8.875% |
|
|
|
|
|
|
200,000 |
|
Senior Exchangeable Notes interest payable semiannually at
1.5% until December 2011 and 1.25% thereafter, due
December 2026 |
|
|
400,000 |
|
|
|
|
|
Revolver interest payable monthly at floating rate,
due in June 2011 |
|
|
|
|
|
|
|
|
U.S. Government guaranteed long-term financing interest
payable semianually at 6.45%, due in semiannual
installments through June 2027 |
|
|
16,596 |
|
|
|
17,406 |
|
|
|
|
|
|
|
|
|
|
|
712,315 |
|
|
|
217,406 |
|
Less current portion |
|
|
810 |
|
|
|
810 |
|
|
|
|
|
|
|
|
Long-term debt |
|
$ |
711,505 |
|
|
$ |
216,596 |
|
|
|
|
|
|
|
|
In December 2006, the Company amended its revolving credit facility to increase it to $250 million
from $150 million. Any balance outstanding on the revolving credit facility is due on June 14,
2011. At December 31, 2006, the Company had no borrowings under this revolving credit facility but
had letters of credit outstanding of approximately $35.6 million, which reduce the Companys
borrowing capacity under the revolving credit facility. Borrowing under the credit facility bear
interest at a LIBOR rate plus margins that depend on the Companys leverage ratio. Indebtedness
under the credit facility is secured by substantially all of the Companys assets, including the
pledge of the stock of the Companys principal subsidiaries. The credit facility contains
customary events of default and requires that the Company satisfy various financial covenants. It
also limits the Companys ability to pay dividends or make other distributions, make acquisitions,
make changes to the Companys capital structure, create liens, incur additional indebtedness or
assume additional decommissioning liabilities. At December 31, 2006, the Company was in compliance
with all such covenants.
The Company has $16.6 million outstanding in U. S. Government guaranteed long-term financing under
Title XI of the Merchant Marine Act of 1936, which is administered by the Maritime Administration
(MARAD) for two 245-foot class liftboats. The debt bears an interest rate of 6.45% per annum and
is payable in equal semi-annual installments of $405,000, on every June 3rd and December
3rd through June 3, 2027. The Companys obligations are secured by mortgages on the two
liftboats. In accordance with the agreement, the Company is required to comply
with certain covenants and restrictions, including the maintenance of minimum net worth and
debt-to-equity requirements. At December 31, 2006, the Company was in compliance with all such
covenants. This long-term financing ranks equally with the bank credit facility as both are
secured by different collateral.
59
In the second quarter of 2006, the Company completed a tender offer for approximately 97.6% of its
$200 million outstanding of 8 7/8% unsecured senior notes due 2011. The cash consideration for the
tender offer was $1,045.63 per $1,000 in aggregate principal amount of senior notes tendered. In
conjunction with the tender offer, the Company also received consents to amend the indenture
pursuant to which the senior notes were issued to eliminate from the indenture substantially all of
the restrictive covenants and certain events of default. After the tender offer was completed, the
Company redeemed the remaining outstanding senior notes in accordance with the indenture at the
redemption price of $1,044.38 per $1,000 of the principal amount redeemed. The Company recognized
a loss on the early extinguishment of debt of approximately $12.6 million, which included the
tender premiums, redemption premiums, fees and expenses and the write-off of the remaining
unamortized debt acquisition costs associated with these notes.
In May 2006, the Company issued $300 million of 6 7/8% unsecured senior notes due 2014. The Company
used the net proceeds to refinance the 8 7/8% senior notes due 2011 and related tender and
redemption premiums, fees and related expenses, and to fund the equity investment in Coldren
Resources. The indenture governing the notes requires semi-annual interest payments, on every June
1st and December 1st through the maturity date of June 1, 2014. The
indenture contains certain covenants that, among other things, restrict the Company from incurring
additional debt, repurchasing capital stock, paying dividends or making other distributions,
incurring liens, selling assets or entering into certain mergers or acquisitions. At December 31,
2006, the Company was in compliance with all such covenants.
In December 2006, SESI, L.L.C. (Issuer), a wholly owned subsidiary of the Company, issued $400
million of 1.50% Senior Exchangeable Notes due 2026. The notes bear interest at a rate of 1.50%
per annum and decrease to 1.25% per annum on December 15, 2011. Interest on the notes is payable
semi-annually in arrears on December 15th and June 15th of each year,
beginning June 15, 2007. The notes do not contain any restrictive financial covenants.
The notes are the Issuers senior, unsecured obligations, and rank equal in right of payment to all
other existing and future senior indebtedness of the Issuer. The notes are guaranteed on a senior,
unsecured basis by the Company and the Companys current domestic subsidiaries that guarantee the
Issuers outstanding 6 7/8% Senior Notes due 2014. Future subsidiaries that guarantee any
indebtedness of the Issuer, the Company or a domestic subsidiary will also guarantee the notes.
Under certain circumstances, holders may exchange the notes for shares of the Companys common
stock. The initial exchange rate is 21.9414 shares of common stock per $1,000 principal amount of
notes. This is equal to an initial exchange price of $45.58 per share. The exchange price
represents a 35% premium over the closing share price at the date of issuance. The notes may be
exchanged under the following circumstances:
|
|
|
during any fiscal quarter (and only during such fiscal quarter) commencing after March
31, 2007, if the last reported sale price of the Companys common stock is greater than or
equal to 135% of the applicable exchange price of the notes for at least 20 trading days in
the period of 30 consecutive trading days ending on the last trading day of the preceding
fiscal quarter; |
|
|
|
|
prior to December 15, 2011, during the five business-day period after any ten
consecutive trading-day period (the measurement period) in which the trading price of
$1,000 principal amount of notes for each trading day in the measurement period was less
than 95% of the product of the last reported sale price of the Companys common stock and
the exchange rate on such trading day; |
|
|
|
|
if the notes have been called for redemption; |
|
|
|
|
upon the occurrence of specified corporate transactions; or |
|
|
|
|
at any time beginning on September 15, 2026, and ending at the close of business on the
second business day immediately preceding the maturity date. |
In connection with the exchangeable note transaction, the Company simultaneously entered into
agreements with affiliates of the initial purchasers to purchase call options and sell warrants on
its common stock. The Company may exercise the call options it purchased at any time to acquire
approximately 8.8 million shares of its common
stock at a strike price of $45.58 per share. The owners of the warrants may exercise the warrants
to purchase from the Company approximately 8.8 million shares of the Companys common stock at a
price of $59.42 per share, subject to certain anti-dilution and other customary adjustments. The
warrants may be settled in cash, in shares or in
60
a combination of cash and shares, at the Companys
option. The Company paid $96 million (exclusive of a $35.5 million tax benefit) to acquire the
call options and received $60.4 million as a result of the sale of the warrants. The $60.5
million purchase of the call options, net of the related tax benefit, was recorded as a reduction
to stockholders equity and the sale of the warrants was recorded as an increase to stockholders
equity in accordance with the guidance in EITF Issue No. 00-19, Accounting for Derivative
Financial Instruments Indexed to, and Potentially Settled in, a Companys Own Stock. Subsequent
changes in the fair value of the call options and warrants will not be recognized as long as the
instruments remain classified in stockholders equity.
Because the Company entered into the call option and warrant transactions in connection with the
issuance of the exchangeable notes, there will be no impact on basic or dilutive earnings per share
unless the price of the Companys common stock exceeds the initial exchange price of $45.58 per
share. In the event the Companys common stock exceeds $45.58 per share, for the first $1.00 the
price exceeds $45.58, there would be dilution of approximately 188,400 shares and the impact on the
calculation of earnings per share will vary depending on when during the quarter the $45.58 per
share price is reached. As this share price continues to increase, dilution would continue to
occur but at a declining rate. If the call options and warrants settle in the Companys favor, the
Company could be exposed to credit risk related to the other parties to the transactions.
The Company has agreed to file a shelf registration statement covering resales of the notes and
common stock issuable upon the exchange of the notes that is required to become effective no later
than 180 days after the original date of the issuance of the notes. In the event the shelf
registration statement does not become effective as described above, the Issuer has agreed to pay
additional interest of 0.25% per annum for the first 90 days after the occurrence of the event and
0.50% per annum thereafter, provided that no additional interest will accrue with respect to any
period after the second anniversary of the original issuance of the notes. The Company plans to
file a resale registration statement with respect to the exchangeable note transaction in March
2007.
Annual maturities of long-term debt for each of the five fiscal years following December 31, 2006
and thereafter are as follows (in thousands):
|
|
|
|
|
2007 |
|
$ |
810 |
|
2008 |
|
|
810 |
|
2009 |
|
|
810 |
|
2010 |
|
|
810 |
|
2011 |
|
|
810 |
|
Thereafter |
|
|
708,265 |
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
712,315 |
|
|
|
|
|
(9) Income Taxes
The components of income tax expense (benefit) for the years ended December 31, 2006, 2005 and 2004
are as follows (in thousands):
61
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Current |
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
$ |
75,017 |
|
|
$ |
30,745 |
|
|
$ |
87 |
|
State |
|
|
1,373 |
|
|
|
898 |
|
|
|
415 |
|
Foreign |
|
|
11,552 |
|
|
|
6,087 |
|
|
|
5,320 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
87,942 |
|
|
|
37,730 |
|
|
|
5,822 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred |
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
|
16,894 |
|
|
|
1,895 |
|
|
|
17,569 |
|
State |
|
|
1,444 |
|
|
|
94 |
|
|
|
105 |
|
Foreign |
|
|
(2,675 |
) |
|
|
(1,547 |
) |
|
|
(2,440 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15,663 |
|
|
|
442 |
|
|
|
15,234 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
103,605 |
|
|
$ |
38,172 |
|
|
$ |
21,056 |
|
|
|
|
|
|
|
|
|
|
|
Income tax expense differs from the amounts computed by applying the U.S. Federal income tax rate
of 35% to income before income taxes for the years ended December 31, 2006, 2005 and 2004 as
follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Computed expected tax expense |
|
$ |
102,146 |
|
|
$ |
37,111 |
|
|
$ |
19,918 |
|
Increase (decrease) resulting from: |
|
|
|
|
|
|
|
|
|
|
|
|
State and foreign income taxes |
|
|
(14 |
) |
|
|
242 |
|
|
|
178 |
|
Other |
|
|
1,473 |
|
|
|
819 |
|
|
|
960 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense |
|
$ |
103,605 |
|
|
$ |
38,172 |
|
|
$ |
21,056 |
|
|
|
|
|
|
|
|
|
|
|
The significant components of deferred income taxes at December 31, 2006 and 2005 are as follows
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
Deferred tax assets: |
|
|
|
|
|
|
|
|
Allowance for doubtful accounts |
|
$ |
5,598 |
|
|
$ |
1,793 |
|
Operating loss and tax credit carryforwards |
|
|
23,183 |
|
|
|
8,198 |
|
Decommissioning liability |
|
|
45,212 |
|
|
|
45,106 |
|
Deferred interest expense related to exchangeable notes |
|
|
35,520 |
|
|
|
|
|
Other |
|
|
13,183 |
|
|
|
9,476 |
|
|
|
|
|
|
|
|
|
|
|
122,696 |
|
|
|
64,573 |
|
Valuation allowance |
|
|
(6,370 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax assets |
|
|
116,326 |
|
|
|
64,573 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities: |
|
|
|
|
|
|
|
|
Property, plant and equipment |
|
|
168,523 |
|
|
|
137,185 |
|
Note receivable |
|
|
11,455 |
|
|
|
11,668 |
|
Goodwill and other intangible assets |
|
|
46,810 |
|
|
|
6,094 |
|
Other |
|
|
1,549 |
|
|
|
1,525 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities |
|
|
228,337 |
|
|
|
156,472 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability |
|
$ |
112,011 |
|
|
$ |
91,899 |
|
|
|
|
|
|
|
|
The net deferred tax assets reflect managements estimate of the amount that will be realized from
future profitability and the reversal of taxable temporary differences that can be predicted with
reasonable certainty. A
62
valuation allowance is recognized if it is more likely than not that at
least some portion of any deferred tax asset will not be realized. As of December 31, 2006, the
Company has recorded a valuation allowance of $6.4 million against its deferred tax assets to
reflect the estimated expiration of net operating loss carryforwards.
At December 31, 2006 the Company has approximately $43.4 million in net operating loss
carryforwards, which are available to reduce future taxable income. The expiration dates for
utilization of the loss carryforwards is 2018 through 2020. Utilization of the net operating loss
carryforwards will be subject to annual limitations due to the ownership change limitations
provided by the Internal Revenue Code of 1986, as amended. The annual limitations may result in
expiration of the net operating loss before full utilization.
As of December 31, 2006, the Company has an estimated $5.3 million foreign tax credit carryforward
with expiration dates from 2011 through 2014. As of December 31, 2006, the Company also has
various state net operating loss carryforwards of an estimated $30.2 million with expiration dates
from 2015 through 2019.
The Company has not provided United States tax expense on earnings of its foreign subsidiaries,
since the Company has reinvested or expects to reinvest the undistributed earnings indefinitely.
As of December 31, 2006, the undistributed earnings of the Companys foreign subsidiaries were
approximately $46.6 million. If these earnings are repatriated to the United States in the future,
additional tax provisions may be required. It is not practicable to estimate the amount of taxes
that might be payable on such undistributed earnings.
(10) Stockholders Equity
In December 2006, concurrently with the closing of our 1.5% Senior Exchangeable Notes, the Company
repurchased and retired 4,739,300 shares of its outstanding common stock at a price of $33.76 per
share, or approximately $160 million in the aggregate, in privately negotiated block trades through
one of the initial purchasers of the notes.
Also in December 2006, the Company issued 5,369,888 shares of common stock value at $25.39 per
share (the average closing market price per share for the five trading day period beginning two
trading days before the acquisition announcement date of September 25, 2006) totaling $136.3
million for the acquisition of Warrior Energy Services Corporation.
In connection with the exchangeable note transaction, the Company simultaneously entered into
agreements with affiliates of the initial purchasers to purchase call options and sell warrants on
its common stock. The Company may exercise the call options it purchased at any time to acquire
approximately 8.8 million shares of its common stock at a strike price of $45.58 per share. The
owners of the warrants may exercise the warrants to purchase from the Company approximately 8.8
million shares of the Companys common stock at a price of $59.42 per share, subject to certain
anti-dilution and other customary adjustments. The warrants may be settled in cash, in shares or
in a combination of cash and shares, at the Companys option. The Company paid $96 million
(exclusive of a $35.5 million tax benefit) to acquire the call options and received $60.4 million
as a result of the sale of the warrants. The $60.5 million purchase of the call options, net of
the related tax benefit, was recorded as a reduction to stockholders equity and the sale of the
warrants was recorded as an increase to stockholders equity in accordance with the guidance in
EITF Issue No. 00-19, Accounting for Derivative Financial Instruments Indexed to, and Potentially
Settled in, a Companys Own Stock. Subsequent changes in the fair value of the call options and
warrants will not be recognized as long as the instruments remain classified in stockholders
equity.
In 2004, the Company sold 11,151,121 shares of common stock (including 1,454,494 shares pursuant to
the exercise of the underwriters over-allotment option) that generated net proceeds of
approximately $130 million, after deducting underwriting discounts and commissions and the offering
expenses. The Company used most of the net proceeds to repurchase 9,696,627 shares of its common
stock from First Reserve Fund VII, Limited Partnership and First Reserve Fund VIII, L.P. The
shares repurchased by the Company from the First Reserve funds were retired immediately upon
repurchase.
63
(11) Reduction in Value of Assets
During the year ended December 31, 2005, the Company reduced the value of two of its mature oil and
gas properties by approximately $2.1 million due to well issues affecting production rates and
operating costs. The Company deemed it to be uneconomical to perform additional production
enhancement work to maintain production at these properties.
Also during the year ended December 31, 2005, the Companys oil spill containment boom
manufacturing facility suffered damage from Hurricane Katrina and experienced difficulty in
resuming normal business operations. As a result, the Company elected not to reopen this
manufacturing facility and sell the remaining oil spill containment boom inventory. The value of
the assets of this business (which consist primarily of inventory and property and equipment) were
reduced by approximately $1.1 million to their estimated net realizable value.
In the first quarter of 2006, the Company sold its environmental subsidiary for approximately $18.7
million in cash. The Company reduced the net asset value of this subsidiary by $3.8 million in
2005 to the approximate sales price.
(12) Gain on Sale of Liftboats
Effective June 1, 2005, the Company sold 17 of its rental liftboats with leg-lengths from 105 feet
to 135 feet for $19.6 million in cash (net of costs to sell). This constituted all of the
Companys rental fleet of liftboats with leg-lengths of 135 feet or less. The Company recorded a
gain of $3.5 million in the year ended December 31, 2005 as a result of this transaction.
(13) Profit-Sharing Plan
The Company maintains a defined contribution profit-sharing plan for employees who have satisfied
minimum service and age requirements. Employees may contribute up to 75% of their earnings to the
plans limited by the annual dollar limitations imposed by the Internal Revenue Service. The
Company provides a discretionary match, not to exceed 5% of an employees salary. The Company made
contributions of approximately $2.7 million, $1.9 million and $1.7 million in 2006, 2005 and 2004,
respectively.
The Company has a nonqualified defined contribution deferred compensation plan which allows certain
highly-compensated employees the option to defer up to 75% of their salary and up to 100% of their
bonus compensation to the plan. Payments are made to participants based on their annual enrollment
elections and plan balance. Participants earn a return on their deferred compensation that is
based on hypothetical investments in certain mutual funds. Changes in market value of these
hypothetical participant investments are reflected as an adjustment to the deferred compensation
liability of the Company with an offset to compensation expense. As of December 31, 2006 and 2005,
the liability of the Company to the participants was approximately $3.9 million and $1.5 million,
respectively, and is recorded in Other Long-Term Liabilities, which reflects the accumulated
participant deferrals and earnings as of that date. The Company makes contributions equal to the
participant deferrals into life insurance which is invested in mutual funds similar to the
participants elections. A change in market value of the life insurance is reflected as an
adjustment to the deferred compensation plan asset with an offset to interest income or expense.
As of December 31, 2006 and 2005, the deferred contribution plan asset was approximately $4.3
million and $1.4 million, respectively, and is recorded in Intangible and Other Long-Term Assets.
(14) Commitments and Contingencies
The Company leases many of its office, service and assembly facilities under operating leases. The
leases expire at various dates over the next several years. Total rent expense was approximately
$4.2 million in 2006, $4.3 million in 2005 and $4.2 million in 2004. Future minimum lease payments
under non-cancelable leases for the five years ending December 31, 2007 through 2011 and thereafter
are as follows (amounts in thousands): $7,003, $4,939, $2,932, $1,628, $973 and $13,692,
respectively.
From time to time, the Company is involved in litigation arising out of operations in the normal
course of business. In managements opinion, the Company is not involved in any litigation, the
outcome of which would have a material effect on its financial position, results of operations or
liquidity.
64
(15) Segment Information
Business Segments
The Company has four reportable segments: well intervention, rental tools, marine, and oil and gas.
The well intervention segment provides: production-related services used to enhance, extend and
maintain oil and gas production, which include mechanical wireline, hydraulic workover and
snubbing, well control, coiled tubing, electric line, pumping and stimulation and wellbore
evaluation services; well plug and abandonment services; and other oilfield services used to
support drilling and production operations. The rental tools segment rents and sells stabilizers,
drill pipe, tubulars and specialized equipment for use with onshore and offshore oil and gas well
drilling, completion, production and workover activities. It also provides on-site accommodations
and bolting and machining services. The marine segment operates liftboats for production service
activities, as well as oil and gas production facility maintenance, construction operations and
platform removals. The oil and gas segment acquires mature oil and gas properties and produces and
sells any remaining economic oil and gas reserves. Oil and gas eliminations represent products and
services provided to the oil and gas segment by the Companys three other segments.
The accounting policies of the reportable segments are the same as those described in note 1 of
these Notes to the Consolidated Financial Statements. The Company evaluates the performance of its
operating segments based on operating profits or losses. Segment revenues reflect direct sales of
products and services for that segment, and each segment records direct expenses related
to its employees and its operations. Identifiable assets are primarily those assets directly used
in the operations of each segment. The equity-method investment in Coldren Resources of
approximately $63.6 million is included in the identifiable assets of the oil and gas segment.
Summarized financial information concerning the Companys segments as of December 31, 2006, 2005
and 2004 and for the years then ended is shown in the following tables (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & Gas |
|
|
|
|
Well |
|
Rental |
|
|
|
|
|
|
|
|
|
Eliminations |
|
Consolid. |
2006 |
|
Interven. |
|
Tools |
|
Marine |
|
Oil & Gas |
|
& Unallocated |
|
Total |
|
|
|
Revenues |
|
$ |
469,110 |
|
|
$ |
371,155 |
|
|
$ |
140,115 |
|
|
$ |
127,682 |
|
|
$ |
(14,241 |
) |
|
$ |
1,093,821 |
|
Cost of services, rentals, and sales |
|
|
269,631 |
|
|
|
115,898 |
|
|
|
56,189 |
|
|
|
70,028 |
|
|
|
(14,241 |
) |
|
|
497,505 |
|
Depreciation, depletion,
amortization and accretion |
|
|
18,810 |
|
|
|
52,234 |
|
|
|
8,600 |
|
|
|
31,367 |
|
|
|
|
|
|
|
111,011 |
|
General and administrative |
|
|
77,758 |
|
|
|
70,306 |
|
|
|
11,432 |
|
|
|
8,920 |
|
|
|
|
|
|
|
168,416 |
|
Income from operations |
|
|
102,911 |
|
|
|
132,717 |
|
|
|
63,894 |
|
|
|
17,367 |
|
|
|
|
|
|
|
316,889 |
|
Interest expense, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(22,950 |
) |
|
|
(22,950 |
) |
Interest income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,194 |
|
|
|
3,418 |
|
|
|
4,612 |
|
Loss on early extinguishment
of debt |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12,596 |
) |
|
|
(12,596 |
) |
Earnings from equity-method
investments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,891 |
|
|
|
|
|
|
|
5,891 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
$ |
102,911 |
|
|
$ |
132,717 |
|
|
$ |
63,894 |
|
|
$ |
24,452 |
|
|
$ |
(32,128 |
) |
|
$ |
291,846 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Identifiable assets |
|
$ |
807,358 |
|
|
$ |
533,928 |
|
|
$ |
187,597 |
|
|
$ |
318,297 |
|
|
$ |
27,298 |
|
|
$ |
1,874,478 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
$ |
54,104 |
|
|
$ |
111,270 |
|
|
$ |
10,412 |
|
|
$ |
64,237 |
|
|
$ |
2,913 |
|
|
$ |
242,936 |
|
65
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & Gas |
|
|
|
|
Well |
|
Rental |
|
|
|
|
|
|
|
|
|
Eliminations |
|
Consolid. |
2005 |
|
Interven. |
|
Tools |
|
Marine |
|
Oil & Gas |
|
& Unallocated |
|
Total |
|
|
|
Revenues |
|
$ |
339,609 |
|
|
$ |
243,536 |
|
|
$ |
87,267 |
|
|
$ |
78,911 |
|
|
$ |
(13,989 |
) |
|
$ |
735,334 |
|
Cost of services, rentals, and sales |
|
|
213,638 |
|
|
|
82,562 |
|
|
|
47,989 |
|
|
|
45,804 |
|
|
|
(13,989 |
) |
|
|
376,004 |
|
Depreciation, depletion,
amortization and accretion |
|
|
18,135 |
|
|
|
42,445 |
|
|
|
8,214 |
|
|
|
20,494 |
|
|
|
|
|
|
|
89,288 |
|
General and administrative |
|
|
71,027 |
|
|
|
54,533 |
|
|
|
9,889 |
|
|
|
5,540 |
|
|
|
|
|
|
|
140,989 |
|
Reduction in value of assets |
|
|
4,850 |
|
|
|
|
|
|
|
|
|
|
|
2,144 |
|
|
|
|
|
|
|
6,994 |
|
Gain on sale of liftboats |
|
|
|
|
|
|
|
|
|
|
3,544 |
|
|
|
|
|
|
|
|
|
|
|
3,544 |
|
Income from operations |
|
|
31,959 |
|
|
|
63,996 |
|
|
|
24,719 |
|
|
|
4,929 |
|
|
|
|
|
|
|
125,603 |
|
Interest expense, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(21,862 |
) |
|
|
(21,862 |
) |
Interest income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,160 |
|
|
|
1,041 |
|
|
|
2,201 |
|
Earnings from equity-method
investments |
|
|
|
|
|
|
1,339 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,339 |
|
Reduction in value of equity-
method investment |
|
|
|
|
|
|
(1,250 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,250 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
$ |
31,959 |
|
|
$ |
64,085 |
|
|
$ |
24,719 |
|
|
$ |
6,089 |
|
|
$ |
(20,821 |
) |
|
$ |
106,031 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Identifiable assets |
|
$ |
332,996 |
|
|
$ |
405,527 |
|
|
$ |
203,718 |
|
|
$ |
147,667 |
|
|
$ |
7,342 |
|
|
$ |
1,097,250 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
$ |
24,847 |
|
|
$ |
70,227 |
|
|
$ |
10,399 |
|
|
$ |
19,693 |
|
|
$ |
|
|
|
$ |
125,166 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil & Gas |
|
|
|
|
Well |
|
Rental |
|
|
|
|
|
|
|
|
|
Eliminations |
|
Consolid. |
2004 |
|
Interven. |
|
Tools |
|
Marine |
|
Oil & Gas |
|
& Unallocated |
|
Total |
|
|
|
Revenues |
|
$ |
295,690 |
|
|
$ |
170,064 |
|
|
$ |
69,808 |
|
|
$ |
37,008 |
|
|
$ |
(8,231 |
) |
|
$ |
564,339 |
|
Costs of services, rentals and sales |
|
|
189,858 |
|
|
|
57,353 |
|
|
|
49,581 |
|
|
|
21,547 |
|
|
|
(8,231 |
) |
|
|
310,108 |
|
Depreciation, depletion,
amortization and accretion |
|
|
17,435 |
|
|
|
32,527 |
|
|
|
7,362 |
|
|
|
10,013 |
|
|
|
|
|
|
|
67,337 |
|
General and administrative |
|
|
58,703 |
|
|
|
42,165 |
|
|
|
7,085 |
|
|
|
2,652 |
|
|
|
|
|
|
|
110,605 |
|
Income from operations |
|
|
29,694 |
|
|
|
38,019 |
|
|
|
5,780 |
|
|
|
2,796 |
|
|
|
|
|
|
|
76,289 |
|
Interest expense, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(22,476 |
) |
|
|
(22,476 |
) |
Interest income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,648 |
|
|
|
118 |
|
|
|
1,766 |
|
Earnings from equity-method
investments |
|
|
|
|
|
|
1,329 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,329 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
$ |
29,694 |
|
|
$ |
39,348 |
|
|
$ |
5,780 |
|
|
$ |
4,444 |
|
|
$ |
(22,358 |
) |
|
$ |
56,908 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Identifiable assets |
|
$ |
313,431 |
|
|
$ |
357,762 |
|
|
$ |
184,928 |
|
|
$ |
141,179 |
|
|
$ |
6,613 |
|
|
$ |
1,003,913 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
$ |
12,735 |
|
|
$ |
50,687 |
|
|
$ |
5,523 |
|
|
$ |
5,180 |
|
|
$ |
|
|
|
$ |
74,125 |
|
Geographic Segments
The Company attributes revenue to various countries based on the location of where services are
performed or the destination of the rental tools or products sold. Long-lived assets consist
primarily of property, plant, and equipment and are attributed to various countries based on the
physical location of the asset at a given fiscal year-end. The Companys information by geographic
area is as follows (amounts in thousands):
66
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
Long-Lived Assets |
|
|
Years Ended December 31, |
|
December 31, |
|
|
2006 |
|
2005 |
|
2004 |
|
2006 |
|
2005 |
United States |
|
$ |
924,582 |
|
|
$ |
636,062 |
|
|
$ |
476,771 |
|
|
$ |
715,899 |
|
|
$ |
492,602 |
|
Other Countries |
|
|
169,239 |
|
|
|
99,272 |
|
|
|
87,568 |
|
|
|
88,329 |
|
|
|
42,360 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
1,093,821 |
|
|
$ |
735,334 |
|
|
$ |
564,339 |
|
|
$ |
804,228 |
|
|
$ |
534,962 |
|
|
|
|
|
|
(16) Interim Financial Information (Unaudited)
The following is a summary of consolidated interim financial information for the years ended
December 31, 2006 and 2005 (amounts in thousands, except per share data):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
March 31 |
|
June 30 |
|
Sept. 30 |
|
Dec. 31 |
2006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
222,469 |
|
|
$ |
261,759 |
|
|
$ |
290,517 |
|
|
$ |
319,076 |
|
Gross profit |
|
|
115,009 |
|
|
|
141,771 |
|
|
|
161,430 |
|
|
|
178,106 |
|
Net income |
|
|
32,168 |
|
|
|
38,727 |
|
|
|
55,158 |
|
|
|
62,188 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.40 |
|
|
$ |
0.49 |
|
|
$ |
0.69 |
|
|
$ |
0.78 |
|
Diluted |
|
|
0.40 |
|
|
|
0.48 |
|
|
|
0.68 |
|
|
|
0.76 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
March 31 |
|
June 30 |
|
Sept. 30 |
|
Dec. 31 |
2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
173,247 |
|
|
$ |
190,000 |
|
|
$ |
184,101 |
|
|
$ |
187,986 |
|
Gross profit |
|
|
86,829 |
|
|
|
99,348 |
|
|
|
82,704 |
|
|
|
90,449 |
|
Net income |
|
|
17,209 |
|
|
|
25,054 |
|
|
|
9,358 |
|
|
|
16,238 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.22 |
|
|
$ |
0.32 |
|
|
$ |
0.12 |
|
|
$ |
0.20 |
|
Diluted |
|
|
0.22 |
|
|
|
0.32 |
|
|
|
0.12 |
|
|
|
0.20 |
|
(17) Financial Information Related to Guarantor Subsidiaries
In May 2006, SESI, L.L.C. (Issuer), a wholly-owned subsidiary of Superior Energy Services, Inc.
(Parent), issued $300 million of 6 7/8% Senior Notes due 2014 at 98.489%. In December 2006, the
Issuer issued $400 million of 1.5% Senior Exchangeable Notes due 2026. The Parent, along with
substantially all of its subsidiaries, fully and
unconditionally guaranteed the Senior Notes and the 1.5% Senior Exchangeable Notes and such
guarantees are joint and several. All of the guarantor subsidiaries are wholly-owned subsidiaries
of the Issuer. Domestic income taxes are paid by the Parent through a consolidated tax return and
are accounted for by the Parent. The following tables present the condensed consolidating balance
sheets as of December 31, 2006 and 2005 and the consolidating statements of operations and cash
flows for the years ended December 31, 2006, 2005 and 2004.
67
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidating Balance Sheets
December 31, 2006
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non-Guarantor |
|
|
|
|
|
|
|
|
|
Parent |
|
|
Issuer |
|
|
Subsidiaries |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
|
|
|
$ |
1,608 |
|
|
$ |
14,775 |
|
|
$ |
22,587 |
|
|
$ |
|
|
|
$ |
38,970 |
|
Accounts receivable, net |
|
|
|
|
|
|
3,764 |
|
|
|
275,477 |
|
|
|
39,390 |
|
|
|
(14,831 |
) |
|
|
303,800 |
|
Income taxes receivable |
|
|
7,242 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,612 |
) |
|
|
2,630 |
|
Current portion of notes receivable |
|
|
|
|
|
|
|
|
|
|
14,824 |
|
|
|
|
|
|
|
|
|
|
|
14,824 |
|
Prepaid insurance and other |
|
|
|
|
|
|
16,582 |
|
|
|
40,456 |
|
|
|
2,525 |
|
|
|
|
|
|
|
59,563 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets |
|
|
7,242 |
|
|
|
21,954 |
|
|
|
345,532 |
|
|
|
64,502 |
|
|
|
(19,443 |
) |
|
|
419,787 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net |
|
|
|
|
|
|
2,622 |
|
|
|
738,446 |
|
|
|
63,160 |
|
|
|
|
|
|
|
804,228 |
|
Goodwill, net |
|
|
|
|
|
|
|
|
|
|
417,979 |
|
|
|
26,708 |
|
|
|
|
|
|
|
444,687 |
|
Notes receivable |
|
|
|
|
|
|
|
|
|
|
16,137 |
|
|
|
|
|
|
|
|
|
|
|
16,137 |
|
Equity-method investments |
|
|
124,271 |
|
|
|
510,163 |
|
|
|
63,627 |
|
|
|
|
|
|
|
(633,458 |
) |
|
|
64,603 |
|
Intangible and other long-term assets, net |
|
|
|
|
|
|
23,823 |
|
|
|
101,097 |
|
|
|
116 |
|
|
|
|
|
|
|
125,036 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
131,513 |
|
|
$ |
558,562 |
|
|
$ |
1,682,818 |
|
|
$ |
154,486 |
|
|
$ |
(652,901 |
) |
|
$ |
1,874,478 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
|
|
|
$ |
1,045 |
|
|
$ |
58,528 |
|
|
$ |
20,709 |
|
|
$ |
(14,831 |
) |
|
$ |
65,451 |
|
Accrued expenses |
|
|
505 |
|
|
|
27,671 |
|
|
|
104,866 |
|
|
|
8,642 |
|
|
|
|
|
|
|
141,684 |
|
Income taxes payable |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,612 |
|
|
|
(4,612 |
) |
|
|
|
|
Current portion of decommissioning liabilities |
|
|
|
|
|
|
|
|
|
|
35,150 |
|
|
|
|
|
|
|
|
|
|
|
35,150 |
|
Current maturities of long-term debt |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
810 |
|
|
|
|
|
|
|
810 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
505 |
|
|
|
28,716 |
|
|
|
198,544 |
|
|
|
34,773 |
|
|
|
(19,443 |
) |
|
|
243,095 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income taxes |
|
|
108,649 |
|
|
|
|
|
|
|
|
|
|
|
3,362 |
|
|
|
|
|
|
|
112,011 |
|
Decommissioning liabilities |
|
|
|
|
|
|
|
|
|
|
87,046 |
|
|
|
|
|
|
|
|
|
|
|
87,046 |
|
Long-term debt |
|
|
|
|
|
|
695,719 |
|
|
|
|
|
|
|
15,786 |
|
|
|
|
|
|
|
711,505 |
|
Intercompany payables/(receivables) |
|
|
(224,208 |
) |
|
|
(79,487 |
) |
|
|
782,022 |
|
|
|
23,507 |
|
|
|
(501,834 |
) |
|
|
|
|
Other long-term liabilities |
|
|
6,197 |
|
|
|
3,936 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,133 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders equity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
stock of $.01 par value. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock
of $.001 par value. |
|
|
81 |
|
|
|
|
|
|
|
|
|
|
|
101 |
|
|
|
(101 |
) |
|
|
81 |
|
Additional paid in capital |
|
|
411,374 |
|
|
|
127,173 |
|
|
|
|
|
|
|
4,350 |
|
|
|
(131,523 |
) |
|
|
411,374 |
|
Accumulated other comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,288 |
|
|
|
|
|
|
|
10,288 |
|
Retained earnings (deficit) |
|
|
(171,085 |
) |
|
|
(217,495 |
) |
|
|
615,206 |
|
|
|
62,319 |
|
|
|
|
|
|
|
288,945 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity |
|
|
240,370 |
|
|
|
(90,322 |
) |
|
|
615,206 |
|
|
|
77,058 |
|
|
|
(131,624 |
) |
|
|
710,688 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
131,513 |
|
|
$ |
558,562 |
|
|
$ |
1,682,818 |
|
|
$ |
154,486 |
|
|
$ |
(652,901 |
) |
|
$ |
1,874,478 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
68
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidating Balance Sheets
December 31, 2005
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non-Guarantor |
|
|
|
|
|
|
|
|
|
Parent |
|
|
Issuer |
|
|
Subsidiaries |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
|
|
|
$ |
21,414 |
|
|
$ |
19,421 |
|
|
$ |
13,622 |
|
|
$ |
|
|
|
$ |
54,457 |
|
Accounts receivable, net |
|
|
|
|
|
|
3,748 |
|
|
|
180,670 |
|
|
|
23,332 |
|
|
|
(11,385 |
) |
|
|
196,365 |
|
Current portion of notes receivable |
|
|
|
|
|
|
|
|
|
|
2,364 |
|
|
|
|
|
|
|
|
|
|
|
2,364 |
|
Prepaid insurance and other |
|
|
|
|
|
|
3,039 |
|
|
|
46,237 |
|
|
|
1,840 |
|
|
|
|
|
|
|
51,116 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets |
|
|
|
|
|
|
28,201 |
|
|
|
248,692 |
|
|
|
38,794 |
|
|
|
(11,385 |
) |
|
|
304,302 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net |
|
|
|
|
|
|
|
|
|
|
481,265 |
|
|
|
53,697 |
|
|
|
|
|
|
|
534,962 |
|
Goodwill, net |
|
|
|
|
|
|
|
|
|
|
196,696 |
|
|
|
23,368 |
|
|
|
|
|
|
|
220,064 |
|
Notes receivable |
|
|
|
|
|
|
|
|
|
|
29,483 |
|
|
|
|
|
|
|
|
|
|
|
29,483 |
|
Equity-method investments |
|
|
124,271 |
|
|
|
203,083 |
|
|
|
|
|
|
|
953 |
|
|
|
(327,354 |
) |
|
|
953 |
|
Other assets, net |
|
|
|
|
|
|
6,390 |
|
|
|
553 |
|
|
|
543 |
|
|
|
|
|
|
|
7,486 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
124,271 |
|
|
$ |
237,674 |
|
|
$ |
956,689 |
|
|
$ |
117,355 |
|
|
$ |
(338,739 |
) |
|
$ |
1,097,250 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
|
|
|
$ |
821 |
|
|
$ |
34,790 |
|
|
$ |
17,809 |
|
|
$ |
(11,385 |
) |
|
$ |
42,035 |
|
Accrued expenses |
|
|
269 |
|
|
|
17,300 |
|
|
|
46,025 |
|
|
|
6,332 |
|
|
|
|
|
|
|
69,926 |
|
Income taxes payable |
|
|
9,917 |
|
|
|
|
|
|
|
|
|
|
|
1,436 |
|
|
|
|
|
|
|
11,353 |
|
Fair value of commodity derivative
instruments |
|
|
|
|
|
|
|
|
|
|
10,792 |
|
|
|
|
|
|
|
|
|
|
|
10,792 |
|
Current portion of decommissioning liabilities |
|
|
|
|
|
|
|
|
|
|
14,268 |
|
|
|
|
|
|
|
|
|
|
|
14,268 |
|
Current maturities of long-term debt |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
810 |
|
|
|
|
|
|
|
810 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
10,186 |
|
|
|
18,121 |
|
|
|
105,875 |
|
|
|
26,387 |
|
|
|
(11,385 |
) |
|
|
149,184 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income taxes |
|
|
89,108 |
|
|
|
|
|
|
|
|
|
|
|
2,791 |
|
|
|
|
|
|
|
91,899 |
|
Decommissioning liabilities |
|
|
|
|
|
|
|
|
|
|
107,641 |
|
|
|
|
|
|
|
|
|
|
|
107,641 |
|
Long-term debt |
|
|
|
|
|
|
200,000 |
|
|
|
|
|
|
|
16,596 |
|
|
|
|
|
|
|
216,596 |
|
Intercompany payables/(receivables) |
|
|
(332,937 |
) |
|
|
31,751 |
|
|
|
467,362 |
|
|
|
29,554 |
|
|
|
(195,730 |
) |
|
|
|
|
Other long-term liabilities |
|
|
6,088 |
|
|
|
1,458 |
|
|
|
10 |
|
|
|
|
|
|
|
|
|
|
|
7,556 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders equity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred stock of $.01 par value |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock of $.001 par value |
|
|
79 |
|
|
|
|
|
|
|
|
|
|
|
101 |
|
|
|
(101 |
) |
|
|
79 |
|
Additional paid in capital |
|
|
428,507 |
|
|
|
127,173 |
|
|
|
|
|
|
|
4,350 |
|
|
|
(131,523 |
) |
|
|
428,507 |
|
Accumulated other comprehensive
income (loss), net |
|
|
|
|
|
|
|
|
|
|
(6,799 |
) |
|
|
1,883 |
|
|
|
|
|
|
|
(4,916 |
) |
Retained earnings (deficit) |
|
|
(76,760 |
) |
|
|
(140,829 |
) |
|
|
282,600 |
|
|
|
35,693 |
|
|
|
|
|
|
|
100,704 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total stockholders equity |
|
|
351,826 |
|
|
|
(13,656 |
) |
|
|
275,801 |
|
|
|
42,027 |
|
|
|
(131,624 |
) |
|
|
524,374 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
124,271 |
|
|
$ |
237,674 |
|
|
$ |
956,689 |
|
|
$ |
117,355 |
|
|
$ |
(338,739 |
) |
|
$ |
1,097,250 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
69
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidating Statements of Operations
Year Ended December 31, 2006
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non-Guarantor |
|
|
|
|
|
|
|
|
|
Parent |
|
|
Issuer |
|
|
Subsidiaries |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Oilfield service and rental revenues |
|
$ |
|
|
|
$ |
|
|
|
$ |
868,831 |
|
|
$ |
125,299 |
|
|
$ |
(27,991 |
) |
|
$ |
966,139 |
|
Oil and gas revenues |
|
|
|
|
|
|
|
|
|
|
127,682 |
|
|
|
|
|
|
|
|
|
|
|
127,682 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
|
|
|
|
|
|
|
|
996,513 |
|
|
|
125,299 |
|
|
|
(27,991 |
) |
|
|
1,093,821 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of oilfield services and rentals |
|
|
|
|
|
|
|
|
|
|
390,065 |
|
|
|
65,403 |
|
|
|
(27,991 |
) |
|
|
427,477 |
|
Cost of oil and gas sales |
|
|
|
|
|
|
|
|
|
|
70,028 |
|
|
|
|
|
|
|
|
|
|
|
70,028 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cost of services, rentals and sales |
|
|
|
|
|
|
|
|
|
|
460,093 |
|
|
|
65,403 |
|
|
|
(27,991 |
) |
|
|
497,505 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion, amortization
and accretion |
|
|
|
|
|
|
291 |
|
|
|
100,818 |
|
|
|
9,902 |
|
|
|
|
|
|
|
111,011 |
|
General and administrative expenses |
|
|
501 |
|
|
|
45,168 |
|
|
|
109,964 |
|
|
|
12,783 |
|
|
|
|
|
|
|
168,416 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations |
|
|
(501 |
) |
|
|
(45,459 |
) |
|
|
325,638 |
|
|
|
37,211 |
|
|
|
|
|
|
|
316,889 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net |
|
|
|
|
|
|
(21,239 |
) |
|
|
(598 |
) |
|
|
(1,113 |
) |
|
|
|
|
|
|
(22,950 |
) |
Interest income |
|
|
|
|
|
|
2,605 |
|
|
|
1,698 |
|
|
|
309 |
|
|
|
|
|
|
|
4,612 |
|
Loss on early extinguishment of debt |
|
|
|
|
|
|
(12,596 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12,596 |
) |
Earnings from equity-method
investments |
|
|
|
|
|
|
23 |
|
|
|
5,868 |
|
|
|
|
|
|
|
|
|
|
|
5,891 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
(501 |
) |
|
|
(76,666 |
) |
|
|
332,606 |
|
|
|
36,407 |
|
|
|
|
|
|
|
291,846 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes |
|
|
93,824 |
|
|
|
|
|
|
|
|
|
|
|
9,781 |
|
|
|
|
|
|
|
103,605 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(94,325 |
) |
|
$ |
(76,666 |
) |
|
$ |
332,606 |
|
|
$ |
26,626 |
|
|
$ |
|
|
|
$ |
188,241 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
70
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidating Statements of Operations
Year Ended December 31, 2005
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non-Guarantor |
|
|
|
|
|
|
|
|
|
Parent |
|
|
Issuer |
|
|
Subsidiaries |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Oilfield service and rental revenues |
|
$ |
|
|
|
$ |
|
|
|
$ |
606,415 |
|
|
$ |
76,102 |
|
|
$ |
(26,094 |
) |
|
$ |
656,423 |
|
Oil and gas revenues |
|
|
|
|
|
|
|
|
|
|
78,911 |
|
|
|
|
|
|
|
|
|
|
|
78,911 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
|
|
|
|
|
|
|
|
685,326 |
|
|
|
76,102 |
|
|
|
(26,094 |
) |
|
|
735,334 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of oilfield services and rentals |
|
|
|
|
|
|
|
|
|
|
313,386 |
|
|
|
42,908 |
|
|
|
(26,094 |
) |
|
|
330,200 |
|
Cost of oil and gas sales |
|
|
|
|
|
|
|
|
|
|
45,804 |
|
|
|
|
|
|
|
|
|
|
|
45,804 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cost of services, rentals and sales |
|
|
|
|
|
|
|
|
|
|
359,190 |
|
|
|
42,908 |
|
|
|
(26,094 |
) |
|
|
376,004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion, amortization
and accretion |
|
|
|
|
|
|
|
|
|
|
81,817 |
|
|
|
7,471 |
|
|
|
|
|
|
|
89,288 |
|
General and administrative expenses |
|
|
460 |
|
|
|
29,301 |
|
|
|
101,857 |
|
|
|
9,371 |
|
|
|
|
|
|
|
140,989 |
|
Reduction in value of assets |
|
|
|
|
|
|
|
|
|
|
6,994 |
|
|
|
|
|
|
|
|
|
|
|
6,994 |
|
Gain on sale of liftboats |
|
|
|
|
|
|
|
|
|
|
3,544 |
|
|
|
|
|
|
|
|
|
|
|
3,544 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations |
|
|
(460 |
) |
|
|
(29,301 |
) |
|
|
139,012 |
|
|
|
16,352 |
|
|
|
|
|
|
|
125,603 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net |
|
|
|
|
|
|
(20,585 |
) |
|
|
(6 |
) |
|
|
(1,271 |
) |
|
|
|
|
|
|
(21,862 |
) |
Interest income |
|
|
|
|
|
|
822 |
|
|
|
1,194 |
|
|
|
185 |
|
|
|
|
|
|
|
2,201 |
|
Earnings from equity-method
investments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,339 |
|
|
|
|
|
|
|
1,339 |
|
Reduction in value of equity-method investment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,250 |
) |
|
|
|
|
|
|
(1,250 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
(460 |
) |
|
|
(49,064 |
) |
|
|
140,200 |
|
|
|
15,355 |
|
|
|
|
|
|
|
106,031 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes |
|
|
33,629 |
|
|
|
|
|
|
|
|
|
|
|
4,543 |
|
|
|
|
|
|
|
38,172 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(34,089 |
) |
|
$ |
(49,064 |
) |
|
$ |
140,200 |
|
|
$ |
10,812 |
|
|
$ |
|
|
|
$ |
67,859 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
71
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidating Statements of Operations
Year Ended December 31, 2004
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non-Guarantor |
|
|
|
|
|
|
|
|
|
Parent |
|
|
Issuer |
|
|
Subsidiaries |
|
|
Subsidiaries |
|
|
Eliminations |
|
|
Consolidated |
|
Oilfield service and rental revenues |
|
$ |
|
|
|
$ |
|
|
|
$ |
488,745 |
|
|
$ |
56,666 |
|
|
$ |
(18,080 |
) |
|
$ |
527,331 |
|
Oil and gas revenues |
|
|
|
|
|
|
|
|
|
|
37,008 |
|
|
|
|
|
|
|
|
|
|
|
37,008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
|
|
|
|
|
|
|
|
525,753 |
|
|
|
56,666 |
|
|
|
(18,080 |
) |
|
|
564,339 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of oilfield services and rentals |
|
|
|
|
|
|
|
|
|
|
276,141 |
|
|
|
30,500 |
|
|
|
(18,080 |
) |
|
|
288,561 |
|
Cost of oil and gas sales |
|
|
|
|
|
|
|
|
|
|
21,547 |
|
|
|
|
|
|
|
|
|
|
|
21,547 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cost of services, rentals and sales |
|
|
|
|
|
|
|
|
|
|
297,688 |
|
|
|
30,500 |
|
|
|
(18,080 |
) |
|
|
310,108 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion, amortization |
|
|
|
|
|
|
|
|
|
|
62,185 |
|
|
|
5,152 |
|
|
|
|
|
|
|
67,337 |
|
and accretion |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses |
|
|
429 |
|
|
|
13,966 |
|
|
|
87,420 |
|
|
|
8,790 |
|
|
|
|
|
|
|
110,605 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations |
|
|
(429 |
) |
|
|
(13,966 |
) |
|
|
78,460 |
|
|
|
12,224 |
|
|
|
|
|
|
|
76,289 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net |
|
|
|
|
|
|
(21,108 |
) |
|
|
(102 |
) |
|
|
(1,266 |
) |
|
|
|
|
|
|
(22,476 |
) |
Interest income |
|
|
|
|
|
|
51 |
|
|
|
1,656 |
|
|
|
59 |
|
|
|
|
|
|
|
1,766 |
|
Earnings from equity-method
investments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,329 |
|
|
|
|
|
|
|
1,329 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
(429 |
) |
|
|
(35,023 |
) |
|
|
80,014 |
|
|
|
12,346 |
|
|
|
|
|
|
|
56,908 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes |
|
|
17,708 |
|
|
|
|
|
|
|
|
|
|
|
3,348 |
|
|
|
|
|
|
|
21,056 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(18,137 |
) |
|
$ |
(35,023 |
) |
|
$ |
80,014 |
|
|
$ |
8,998 |
|
|
$ |
|
|
|
$ |
35,852 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
72
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2006
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Guarantor |
|
|
|
|
|
|
Parent |
|
|
Issuer |
|
|
Subsidiaries |
|
|
Subsidiaries |
|
|
Consolidated |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(94,325 |
) |
|
$ |
(76,666 |
) |
|
$ |
332,606 |
|
|
$ |
26,626 |
|
|
$ |
188,241 |
|
Adjustments to reconcile net income to net cash provided
by (used in) operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion, amortization and accretion |
|
|
|
|
|
|
291 |
|
|
|
100,818 |
|
|
|
9,902 |
|
|
|
111,011 |
|
Deferred income taxes |
|
|
18,338 |
|
|
|
|
|
|
|
|
|
|
|
(2,675 |
) |
|
|
15,663 |
|
Stock-based compensation expense |
|
|
|
|
|
|
6,159 |
|
|
|
|
|
|
|
|
|
|
|
6,159 |
|
Earnings from equity-method investments |
|
|
|
|
|
|
(23 |
) |
|
|
(5,868 |
) |
|
|
|
|
|
|
(5,891 |
) |
Write-off of debt acquisition costs |
|
|
|
|
|
|
2,817 |
|
|
|
|
|
|
|
|
|
|
|
2,817 |
|
Amortization of debt acquisition costs and note discount |
|
|
|
|
|
|
1,321 |
|
|
|
|
|
|
|
|
|
|
|
1,321 |
|
Changes in operating assets and liabilities, net of
acquisitions and dispositions: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivables |
|
|
|
|
|
|
(16 |
) |
|
|
(73,861 |
) |
|
|
(14,421 |
) |
|
|
(88,298 |
) |
Other, net |
|
|
(3,789 |
) |
|
|
(82 |
) |
|
|
12,553 |
|
|
|
5,210 |
|
|
|
13,892 |
|
Accounts payable |
|
|
|
|
|
|
225 |
|
|
|
4,694 |
|
|
|
2,340 |
|
|
|
7,259 |
|
Accrued expenses |
|
|
236 |
|
|
|
6,583 |
|
|
|
34,725 |
|
|
|
1,835 |
|
|
|
43,379 |
|
Decommissioning liabilities |
|
|
|
|
|
|
|
|
|
|
(2,255 |
) |
|
|
|
|
|
|
(2,255 |
) |
Income taxes |
|
|
(15,971 |
) |
|
|
|
|
|
|
|
|
|
|
2,887 |
|
|
|
(13,084 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities |
|
|
(95,511 |
) |
|
|
(59,391 |
) |
|
|
403,412 |
|
|
|
31,704 |
|
|
|
280,214 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments for capital expenditures |
|
|
|
|
|
|
(2,913 |
) |
|
|
(225,411 |
) |
|
|
(14,612 |
) |
|
|
(242,936 |
) |
Acquisitions of businesses, net of cash acquired |
|
|
|
|
|
|
(239,339 |
) |
|
|
|
|
|
|
|
|
|
|
(239,339 |
) |
Acquisitions of oil and gas properties, net of cash acquired |
|
|
|
|
|
|
|
|
|
|
(46,631 |
) |
|
|
|
|
|
|
(46,631 |
) |
Cash proceeds from sale of subsidiary, net of cash sold |
|
|
|
|
|
|
18,343 |
|
|
|
|
|
|
|
|
|
|
|
18,343 |
|
Cash contributed to equity-method investment |
|
|
|
|
|
|
|
|
|
|
(57,781 |
) |
|
|
|
|
|
|
(57,781 |
) |
Other |
|
|
|
|
|
|
(13,947 |
) |
|
|
313 |
|
|
|
|
|
|
|
(13,634 |
) |
Intercompany receivables/payables |
|
|
286,878 |
|
|
|
(199,669 |
) |
|
|
(78,548 |
) |
|
|
(8,661 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) investing activities |
|
|
286,878 |
|
|
|
(437,525 |
) |
|
|
(408,058 |
) |
|
|
(23,273 |
) |
|
|
(581,978 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from long-term debt |
|
|
|
|
|
|
695,467 |
|
|
|
|
|
|
|
|
|
|
|
695,467 |
|
Principal payments on long-term debt |
|
|
|
|
|
|
(200,000 |
) |
|
|
|
|
|
|
(810 |
) |
|
|
(200,810 |
) |
Payment of debt acquisition costs |
|
|
|
|
|
|
(18,357 |
) |
|
|
|
|
|
|
|
|
|
|
(18,357 |
) |
Purchase of option |
|
|
(96,000 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(96,000 |
) |
Sale of warrant |
|
|
60,400 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
60,400 |
|
Proceeds from exercise of stock options |
|
|
2,803 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,803 |
|
Tax benefit from exercise of stock options |
|
|
1,429 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,429 |
|
Purchase and retirement of stock |
|
|
(159,999 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(159,999 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities |
|
|
(191,367 |
) |
|
|
477,110 |
|
|
|
|
|
|
|
(810 |
) |
|
|
284,933 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of exchange rate changes on cash |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,344 |
|
|
|
1,344 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents |
|
|
|
|
|
|
(19,806 |
) |
|
|
(4,646 |
) |
|
|
8,965 |
|
|
|
(15,487 |
) |
Cash and cash equivalents at beginning of year |
|
|
|
|
|
|
21,414 |
|
|
|
19,421 |
|
|
|
13,622 |
|
|
|
54,457 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year |
|
$ |
|
|
|
$ |
1,608 |
|
|
$ |
14,775 |
|
|
$ |
22,587 |
|
|
$ |
38,970 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
73
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2005
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Guarantor |
|
|
|
|
|
|
Parent |
|
|
Issuer |
|
|
Subsidiaries |
|
|
Subsidiaries |
|
|
Consolidated |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(34,089 |
) |
|
$ |
(49,064 |
) |
|
$ |
140,200 |
|
|
$ |
10,812 |
|
|
$ |
67,859 |
|
Adjustments to reconcile net income to net cash provided
by (used in) operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion, amortization and accretion |
|
|
|
|
|
|
|
|
|
|
81,817 |
|
|
|
7,471 |
|
|
|
89,288 |
|
Deferred income taxes |
|
|
509 |
|
|
|
|
|
|
|
|
|
|
|
(67 |
) |
|
|
442 |
|
Reduction in value of assets and equity-method investment |
|
|
|
|
|
|
|
|
|
|
6,994 |
|
|
|
1,250 |
|
|
|
8,244 |
|
Earnings from equity-method investments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,339 |
) |
|
|
(1,339 |
) |
Amortization of debt acquisition costs and note discount |
|
|
|
|
|
|
1,127 |
|
|
|
|
|
|
|
|
|
|
|
1,127 |
|
Gain on sale of liftboats |
|
|
|
|
|
|
|
|
|
|
(3,544 |
) |
|
|
|
|
|
|
(3,544 |
) |
Changes in operating assets and liabilities, net of
acquisitions: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivables |
|
|
|
|
|
|
(2,026 |
) |
|
|
(21,849 |
) |
|
|
(8,220 |
) |
|
|
(32,095 |
) |
Other, net |
|
|
335 |
|
|
|
568 |
|
|
|
(13,733 |
) |
|
|
1,567 |
|
|
|
(11,263 |
) |
Accounts payable |
|
|
|
|
|
|
35 |
|
|
|
(2,282 |
) |
|
|
7,943 |
|
|
|
5,696 |
|
Accrued expenses |
|
|
253 |
|
|
|
4,006 |
|
|
|
8,844 |
|
|
|
3,496 |
|
|
|
16,599 |
|
Decommissioning liabilities |
|
|
|
|
|
|
|
|
|
|
(8,772 |
) |
|
|
|
|
|
|
(8,772 |
) |
Income taxes |
|
|
25,886 |
|
|
|
|
|
|
|
|
|
|
|
251 |
|
|
|
26,137 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities |
|
|
(7,106 |
) |
|
|
(45,354 |
) |
|
|
187,675 |
|
|
|
23,164 |
|
|
|
158,379 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments for capital expenditures |
|
|
|
|
|
|
|
|
|
|
(111,825 |
) |
|
|
(13,341 |
) |
|
|
(125,166 |
) |
Acquisitions of businesses, net of cash acquired |
|
|
|
|
|
|
(6,435 |
) |
|
|
|
|
|
|
|
|
|
|
(6,435 |
) |
Acquisitions of oil and gas properties, net of cash acquired |
|
|
|
|
|
|
|
|
|
|
3,686 |
|
|
|
|
|
|
|
3,686 |
|
Cash proceeds from sale of equity-method investment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,489 |
|
|
|
12,489 |
|
Cash proceeds from the sale of liftboats, net |
|
|
|
|
|
|
|
|
|
|
19,588 |
|
|
|
|
|
|
|
19,588 |
|
Other |
|
|
|
|
|
|
(1,410 |
) |
|
|
313 |
|
|
|
|
|
|
|
(1,097 |
) |
Intercompany receivables/payables |
|
|
(11,055 |
) |
|
|
110,004 |
|
|
|
(85,189 |
) |
|
|
(13,760 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) investing activities |
|
|
(11,055 |
) |
|
|
102,159 |
|
|
|
(173,427 |
) |
|
|
(14,612 |
) |
|
|
(96,935 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Principal payments on long-term debt |
|
|
|
|
|
|
(38,500 |
) |
|
|
|
|
|
|
(810 |
) |
|
|
(39,310 |
) |
Payment of debt acquisition costs |
|
|
|
|
|
|
(439 |
) |
|
|
|
|
|
|
|
|
|
|
(439 |
) |
Proceeds from exercise of stock options |
|
|
18,161 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18,161 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities |
|
|
18,161 |
|
|
|
(38,939 |
) |
|
|
|
|
|
|
(810 |
) |
|
|
(21,588 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of exchange rate changes on cash |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(680 |
) |
|
|
(680 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash |
|
|
|
|
|
|
17,866 |
|
|
|
14,248 |
|
|
|
7,062 |
|
|
|
39,176 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at beginning of period |
|
|
|
|
|
|
3,548 |
|
|
|
5,173 |
|
|
|
6,560 |
|
|
|
15,281 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
|
|
|
$ |
21,414 |
|
|
$ |
19,421 |
|
|
$ |
13,622 |
|
|
$ |
54,457 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
74
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidating Statements of Cash Flows
Year Ended December 31,2004
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Guarantor |
|
|
|
|
|
|
Parent |
|
|
Issuer |
|
|
Subsidiaries |
|
|
Subsidiaries |
|
|
Consolidated |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(18,137 |
) |
|
$ |
(35,023 |
) |
|
$ |
80,014 |
|
|
$ |
8,998 |
|
|
$ |
35,852 |
|
Adjustments to reconcile net income to net cash provided
by (used in) operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion, amortization and accretion |
|
|
|
|
|
|
|
|
|
|
62,185 |
|
|
|
5,152 |
|
|
|
67,337 |
|
Deferred income taxes |
|
|
14,400 |
|
|
|
|
|
|
|
|
|
|
|
834 |
|
|
|
15,234 |
|
Earnings from equity-method investments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,329 |
) |
|
|
(1,329 |
) |
Amortization of debt acquisition costs and note discount |
|
|
|
|
|
|
887 |
|
|
|
|
|
|
|
|
|
|
|
887 |
|
Changes in operating assets and liabilities, net of
acquisitions: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Receivables |
|
|
|
|
|
|
(1,416 |
) |
|
|
(28,517 |
) |
|
|
(5,346 |
) |
|
|
(35,279 |
) |
Other, net |
|
|
|
|
|
|
(774 |
) |
|
|
(7,278 |
) |
|
|
(1,294 |
) |
|
|
(9,346 |
) |
Accounts payable |
|
|
|
|
|
|
64 |
|
|
|
11,012 |
|
|
|
5,066 |
|
|
|
16,142 |
|
Accrued expenses |
|
|
(5 |
) |
|
|
(8,034 |
) |
|
|
21,241 |
|
|
|
664 |
|
|
|
13,866 |
|
Decommissioning liabilities |
|
|
|
|
|
|
|
|
|
|
(9,157 |
) |
|
|
|
|
|
|
(9,157 |
) |
Income taxes |
|
|
(3,690 |
) |
|
|
|
|
|
|
|
|
|
|
814 |
|
|
|
(2,876 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities |
|
|
(7,432 |
) |
|
|
(44,296 |
) |
|
|
129,500 |
|
|
|
13,559 |
|
|
|
91,331 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments for capital expenditures |
|
|
|
|
|
|
|
|
|
|
(69,385 |
) |
|
|
(4,740 |
) |
|
|
(74,125 |
) |
Acquisitions of businesses, net of cash acquired |
|
|
|
|
|
|
(24,361 |
) |
|
|
|
|
|
|
|
|
|
|
(24,361 |
) |
Acquisitions of oil and gas properties, net of cash acquired |
|
|
|
|
|
|
|
|
|
|
(10,676 |
) |
|
|
|
|
|
|
(10,676 |
) |
Intercompany receivables/payables |
|
|
(19,666 |
) |
|
|
76,090 |
|
|
|
(50,990 |
) |
|
|
(5,434 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) investing activities |
|
|
(19,666 |
) |
|
|
51,729 |
|
|
|
(131,051 |
) |
|
|
(10,174 |
) |
|
|
(109,162 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Principal payments on long-term debt |
|
|
|
|
|
|
(12,903 |
) |
|
|
|
|
|
|
(810 |
) |
|
|
(13,713 |
) |
Payment of debt acquisition costs |
|
|
|
|
|
|
(60 |
) |
|
|
|
|
|
|
|
|
|
|
(60 |
) |
Proceeds from exercise of stock options |
|
|
10,271 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,271 |
|
Proceeds from issuance of stock |
|
|
130,265 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
130,265 |
|
Purchase and retirement of stock |
|
|
(113,438 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(113,438 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities |
|
|
27,098 |
|
|
|
(12,963 |
) |
|
|
|
|
|
|
(810 |
) |
|
|
13,325 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of exchange rate changes on cash |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7 |
) |
|
|
(7 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash |
|
|
|
|
|
|
(5,530 |
) |
|
|
(1,551 |
) |
|
|
2,568 |
|
|
|
(4,513 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at beginning of period |
|
|
|
|
|
|
9,078 |
|
|
|
6,724 |
|
|
|
3,992 |
|
|
|
19,794 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
|
|
|
$ |
3,548 |
|
|
$ |
5,173 |
|
|
$ |
6,560 |
|
|
$ |
15,281 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
75
(18) Supplementary Oil and Natural Gas Disclosures (Unaudited)
The Companys December 31, 2006, 2005 and 2004 estimates of proved reserves are based on reserve
reports prepared by DeGolyer and MacNaughton, independent petroleum engineers. Users of this
information should be aware that the process of estimating quantities of proved and proved
developed natural gas and crude oil reserves is very complex, requiring significant subjective
decisions in the evaluation of all available geological, engineering and economic data for each
reservoir. This data may also change substantially over time as a result of multiple factors
including, but not limited to, additional development activity, evolving production history and
continual reassessment of the viability of production under varying economic conditions.
Consequently, material revisions to existing reserve estimates occur from time to time. Although
every reasonable effort is made to ensure that reserve estimates reported represent the most
accurate assessments possible, the significance of the subjective decisions required and variances
in available data for various reservoirs make these estimates generally less precise than other
estimates presented in connection with financial statement disclosures. Proved reserves are
estimated quantities of natural gas, crude oil and condensate that geological and engineering data
demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs
under existing economic and operating conditions. Proved developed reserves are proved reserves
that can be expected to be recovered through existing wells with existing equipment and operating
methods.
The following table sets forth the Companys net proved reserves, including the changes therein,
and proved developed reserves:
|
|
|
|
|
|
|
|
|
|
|
Crude Oil |
|
|
Natural Gas |
|
|
|
(Mbbls) |
|
|
(Mmcf) |
|
Proved-developed and undeveloped reserves: |
|
|
|
|
|
|
|
|
December 31, 2003 |
|
|
190 |
|
|
|
3,224 |
|
Purchase of reserves in place |
|
|
9,232 |
|
|
|
17,968 |
|
Revisions |
|
|
88 |
|
|
|
11,407 |
|
Production |
|
|
(390 |
) |
|
|
(3,219 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2004 |
|
|
9,120 |
|
|
|
29,380 |
|
|
|
|
|
|
|
|
Purchase of reserves in place |
|
|
168 |
|
|
|
2,925 |
|
Revisions |
|
|
1,036 |
|
|
|
(5,294 |
) |
Production |
|
|
(1,221 |
) |
|
|
(3,323 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2005 |
|
|
9,103 |
|
|
|
23,688 |
|
|
|
|
|
|
|
|
Purchase of reserves in place and additions |
|
|
674 |
|
|
|
17,249 |
|
Revisions |
|
|
(265 |
) |
|
|
187 |
|
Production |
|
|
(1,591 |
) |
|
|
(5,483 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006 |
|
|
7,921 |
|
|
|
35,641 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved-developed reserves: |
|
|
|
|
|
|
|
|
December 31, 2004 |
|
|
7,731 |
|
|
|
25,542 |
|
December 31, 2005 |
|
|
7,554 |
|
|
|
21,703 |
|
December 31, 2006 |
|
|
6,709 |
|
|
|
28,982 |
|
Since January 1, 2005 no crude oil or natural gas reserve information has been filed with, or
included in any report to any federal authority or agency other than the SEC and the Energy
Information Administration (EIA). The Company files Form 23, including reserve and other
information with the EIA.
Costs incurred for oil and natural gas property acquisition and development activities for the
years ended December 31, 2006, 2005 and 2004 are as follows (in thousands):
76
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Acquisition of properties proved |
|
$ |
45,948 |
|
|
$ |
9,015 |
|
|
$ |
81,356 |
|
Development costs |
|
|
63,396 |
|
|
|
19,867 |
|
|
|
4,707 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred |
|
$ |
109,344 |
|
|
$ |
28,882 |
|
|
$ |
86,063 |
|
|
|
|
|
|
|
|
|
|
|
Standardized Measure of Discounted Future Net Cash Flows Relating to Reserves
The following information has been developed utilizing procedures prescribed by Statement of
Financial Accounting Standards No. 69 (FAS No. 69), Disclosure about Oil and Gas Producing
Activities. It may be useful for certain comparative purposes, but should not be solely relied
upon in evaluating the Company or its performance. Further, information contained in the following
table should not be considered as representative of realistic assessments of future cash flows, nor
should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of
the current value of the Company.
The Company believes that the following factors should be taken into account in reviewing the
following information: (1) future costs and selling prices will differ from those required to be
used in these calculations; (2) due to future market conditions and governmental regulations,
actual rates of production achieved in future years may vary significantly from the rate of
production assumed in the calculations; (3) selection of a 10% discount rate is arbitrary and may
not be reasonable as a measure of the relative risk inherent in realizing future net oil and gas
revenues; and (4) future net revenues may be subject to different rates of income taxation.
Under the Standardized Measure, future cash inflows were estimated by applying period-end oil and
natural gas prices adjusted for differentials provided by the Company. Future cash inflows were
reduced by estimated future development, abandonment and production costs based on period-end costs
in order to arrive at net cash flow before tax. Future income tax expense has been computed by
applying period-end statutory tax rates to aggregate future net cash flows, reduced by the tax
basis of the properties involved and tax carryforwards. Use of a 10% discount rate is required by
FAS No. 69.
The Companys management does not rely solely upon the following information in making investment
and operating decisions. Such decisions are based upon a wide range of factors, including
estimates of probable as well as proved reserves and varying price and cost assumptions considered
more representative of a range of possible economic conditions that may be anticipated.
The standardized measure of discounted future net cash flows relating to proved oil and natural gas
reserves is as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Future cash inflows |
|
$ |
682,384 |
|
|
$ |
792,246 |
|
|
$ |
587,277 |
|
Future production costs |
|
|
(220,108 |
) |
|
|
(155,282 |
) |
|
|
(148,610 |
) |
Future development and abandonment costs |
|
|
(207,676 |
) |
|
|
(195,415 |
) |
|
|
(153,230 |
) |
Future income tax expense |
|
|
(59,976 |
) |
|
|
(171,058 |
) |
|
|
(119,567 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows after income taxes |
|
|
194,624 |
|
|
|
270,491 |
|
|
|
165,870 |
|
10% annual discount for estimated timing of cash flows |
|
|
15,883 |
|
|
|
65,386 |
|
|
|
29,363 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows |
|
$ |
178,741 |
|
|
$ |
205,105 |
|
|
$ |
136,507 |
|
|
|
|
|
|
|
|
|
|
|
A summary of the changes in the standardized measure of discounted future net cash flows
applicable to proved oil and natural gas reserves for the years ended December 31, 2006, 2005 and
2004 is as follows (in thousands):
77
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
Beginning of the period |
|
$ |
205,105 |
|
|
$ |
136,507 |
|
|
$ |
3,990 |
|
Sales and transfers of oil and natural gas produced,
net of production costs |
|
|
(55,184 |
) |
|
|
(34,563 |
) |
|
|
(15,467 |
) |
Net changes in prices and production costs |
|
|
(147,633 |
) |
|
|
156,992 |
|
|
|
949 |
|
Revisions of quantity estimates |
|
|
(7,071 |
) |
|
|
4,314 |
|
|
|
46,040 |
|
Development costs incurred |
|
|
(64,254 |
) |
|
|
19,867 |
|
|
|
4,707 |
|
Changes in estimated development costs |
|
|
47,096 |
|
|
|
(46,113 |
) |
|
|
(99,253 |
) |
Extensions and discoveries |
|
|
36,906 |
|
|
|
|
|
|
|
|
|
Purchase and sales of reserves in place |
|
|
70,304 |
|
|
|
18,408 |
|
|
|
282,935 |
|
Changes in production rates (timing) and other |
|
|
(22,080 |
) |
|
|
(25,536 |
) |
|
|
(3,238 |
) |
Accretion of discount |
|
|
33,152 |
|
|
|
22,123 |
|
|
|
656 |
|
Net change in income taxes |
|
|
82,401 |
|
|
|
(46,894 |
) |
|
|
(84,812 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase |
|
|
(26,363 |
) |
|
|
68,598 |
|
|
|
132,517 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of period |
|
$ |
178,742 |
|
|
$ |
205,105 |
|
|
$ |
136,507 |
|
|
|
|
|
|
|
|
|
|
|
The December 31, 2006 amount was estimated by DeGolyer and MacNaughton using a period-end crude
NYMEX price of $61.05 per barrel (bbl), a NYMEX gas price of $5.64 per million British Thermal
units, and price differentials provided by the Company. The December 31, 2005 amount was estimated
by DeGolyer and MacNaughton using a period-end crude NYMEX price of $61.04 per barrel (bbl), a
NYMEX gas price of $9.44 per million British Thermal units, and price differentials provided by the
Company. The December 31, 2004 amount was estimated by DeGolyer and MacNaughton using a period-end
crude NYMEX price of $43.46 per bbl, a Henry Hub gas price of $6.19 per million British Thermal
units, and price differentials provided by the Company. Spot prices as of February 16, 2007 were
$7.503 per million British Thermal units for natural gas and $58.39 per bbl for crude oil.
(19) Accounting Pronouncements
In February 2006, the Financial Accounting Standards Board issued its Statement of Financial
Accounting Standards No. 155 (FAS No. 155), Accounting for Certain Hybrid Financial Instruments
an amendment of FASB Statements No. 133 and 140. FAS No. 155 simplifies accounting for certain
hybrid financial instruments by permitting fair value remeasurement for any hybrid instrument that
contains an embedded derivative that otherwise would require bifurcation and eliminates a
restriction on the passive derivative instruments that a qualifying special-purpose entity may
hold. FAS No. 155 is effective for all financial instruments acquired, issued or subject to a
remeasurement (new basis) event occurring after the beginning of an entitys first fiscal year that
begins after September 15, 2006. The adoption of FAS No. 155 has not had an impact on the
Companys results of operations or our financial position.
In July 2006, the Financial Accounting Standards Board issued FASB Interpretation No. 48 (FIN 48),
Accounting for Uncertainty in Income Taxes an interpretation of FASB Statement No. 109. FIN 48
provides guidance on measurement and recognition in accounting for income tax uncertainties and
also requires expanded financial statement disclosure. The Company has evaluated the impact of FIN
48 and does not expect it to have a material impact on its results of operations or financial
condition. This interpretation is effective for fiscal years beginning after December 15, 2006.
In September 2006, the Financial Accounting Standards Board issued its Statement of Financial
Accounting Standards No. 157 (FAS No. 157), Fair Value Measurements. FAS No. 157 establishes a
framework for measuring fair value in generally accepted accounting principles, and expands
disclosures about fair value measurements. FAS No. 157 is effective for financial statements
issued for fiscal years beginning after November 15, 2007. The Company is currently evaluating the
impact that FAS No. 157 will have on its results of operations and financial position.
78
In September 2006, the Financial Accounting Standards Board issued its Statement of Financial
Accounting Standards No. 158 (FAS No. 158), Employers Accounting for Defined Benefit Pension and
Other Postretirement Plans an Amendment of FASB Statements No. 87, 88, 106, and 132(R). FAS No.
158 requires recognition of the overfunded or underfunded status of a defined benefit
postretirement plan (other than a multiemployer plan) as an asset or liability on the balance sheet
and the recognition of changes in the funded status in the year in which the changes occur though
comprehensive income. FAS No. 158 also requires and employer to measure the funded status of a
plan as of the end of the fiscal year. FAS No. 158 is effective for fiscal years ending after
December 15, 2006, except for the measurement date provisions which are effective for fiscal years
ending after December 15, 2008. The adoption of FAS No. 158 has not had an impact on the Companys
results of operations or financial position.
In September 2006, the Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin
No. 108 (SAB 108), Considering the Effects of Prior Year Misstatements when Quantifying
Misstatements in Current Year Financial Statements. SAB 108 provides guidance on the
consideration of effects of prior year misstatements in quantifying current year misstatements for
the purpose of a materiality assessment. SAB 108 requires the analysis of misstatements using both
a balance sheet and income statement approach and contains guidance on correcting errors under the
dual approach, as well as providing transition guidance for correcting errors existing in prior
years. SAB 108 is effective for the first fiscal year ending after November 15, 2006, with early
application encouraged. The adoption of SAB 108 did not have a material impact on the Companys
results of operations or financial position.
79
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure
None.
Item 9A. Controls and Procedures
Our management has established and maintains a system of disclosure controls and procedures to
provide reasonable assurances that information required to be disclosed by us in the reports that
we file or submit under the Securities Exchange Act of 1934 is appropriately recorded, processed,
summarized and reported within the time periods specified by the Securities and Exchange
Commission. Based on that evaluation, our principal executive and financial officers have
concluded that our disclosure controls and procedures as of December 31, 2006 are effective at the
reasonable assurance level. Managements report and the independent registered public accounting
firms attestation report are included in Part II, Item 8 under the captions Managements Report
on Internal Control over Financial Reporting and Independent Registered Public Accounting Firms
Report, and are incorporated herein by reference.
There has been no change in our internal control over financial reporting during the quarter ended
December 31, 2006 that has materially affected, or is reasonably likely to materially affect, our
internal control over financial reporting.
Item 9B. Other Information
None.
80
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Information relating to our executive officers is included in Part I, Item 4A. Information
relating to our Code of Business Ethics and Conduct that applies to our senior financial officers
is included in Part I, Item 1. Other information required by this item will be contained in our
definitive proxy statement to be filed pursuant to Regulation 14A and is incorporated herein by
reference.
Item 11. Executive Compensation
Information required by this item will be contained in our definitive proxy statement to be filed
pursuant to Regulation 14A and is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
Information required by this item will be contained in our definitive proxy statement to be filed
pursuant to Regulation 14A and is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information required by this item will be contained in our definitive proxy statement to be filed
pursuant to Regulation 14A and is incorporated herein by reference.
Item 14. Principal Accountant Fees and Services
Information required by this item will be contained in our definitive proxy statement to be filed
pursuant to Regulation 14A and is incorporated herein by reference.
81
PART IV
Item 15. Exhibits and Financial Statement Schedules
(a) (1) Financial Statements
The following financial statements are included in Part II of this Annual Report on Form 10-K:
Managements Report on Internal Control over Financial Reporting
Report of Independent Registered Public Accounting Firm Audit of Financial Statements
Report of Independent Registered Public Accounting Firm Audit of Internal Control over
Financial Reporting
Consolidated Balance Sheets December 31, 2006 and 2005
Consolidated Statements of Operations for the years ended December 31, 2006, 2005 and 2004
Consolidated Statements of Changes in Stockholders Equity for the years ended December 31,
2006, 2005 and 2004
Consolidated Statements of Cash Flows for the years ended December 31, 2006, 2005 and 2004
Notes to Consolidated Financial Statements
(2) Financial Statement Schedule
Schedule II Valuation and Qualifying Accounts for the years ended December 31, 2006, 2005 and
2004
All other schedules are omitted because they are not applicable or the required information is
included in the consolidated financial statements or notes thereto.
(3) Exhibits
|
|
|
Exhibit No. |
|
Description |
|
|
|
2.1
|
|
Agreement and Plan of Merger, dated September 22, 2006, by
and among the Company, SPN Acquisition Sub, Inc. and Warrior
Energy Services Corporation (incorporated herein by
reference to Exhibit 2.1 the Companys Form 8-K filed
September 25, 2006). |
|
|
|
3.1
|
|
Certificate of Incorporation of the Company (incorporated
herein by reference to the Companys Quarterly Report on
Form 10-QSB for the quarter ended March 31, 1996). |
|
|
|
3.2
|
|
Certificate of Amendment to the Companys Certificate of
Incorporation (incorporated herein by reference to the
Companys Quarterly Report on Form 10-Q for the quarter
ended June 30, 1999). |
|
|
|
3.3
|
|
Amended and Restated Bylaws of the Company (incorporated
herein by reference to Exhibit 3.1 to the Companys Form 8-K
filed on November 15, 2004). |
|
|
|
4.1
|
|
Specimen Stock Certificate (incorporated herein by reference
to Amendment No. 1 to the Companys Form S-4 on Form SB-2
(Registration Statement No. 33-94454)). |
82
|
|
|
Exhibit No. |
|
Description |
4.2
|
|
Indenture dated May 2, 2001, by and among SESI, L.L.C., the
Company, the Subsidiary Guarantors named therein and the
Bank of New York as trustee (incorporated herein by
reference to the Companys Quarterly Report on Form 10-Q for
the quarter ended March 31, 2001), as amended by First
Supplemental Indenture, dated as of July 9, 2001, by and
among SESI, L.L.C., Wild Well Control, Inc., Blowout Tools,
Inc. and the Bank of New York, as trustee (incorporated
herein by reference to the Companys Registration Statement
on Form S-4 (Registration No. 333-64946)), as amended by
Second Supplemental Indenture, dated as of September 1, 2001
by and among SESI, L.L.C., Workstrings, L.L.C., Technical
Limit Drillstrings, Inc. and the Bank of New York, as
trustee (incorporated herein by reference to the Companys
Quarterly Report on Form 10-Q for the quarter ended
September 30, 2001), as amended by Fourth Supplemental
Indenture, dated as of April 20, 2005, but effective as of
July 1, 2004, by and among SESI, L.L.C., SPN Resources, LLC,
and the Bank of New York, as trustee (incorporated herein by
reference to Exhibit 4.1 to the Companys Form 8-K filed
April 20, 2005), as amended by Fifth Supplemental Indenture,
dated as of November 15, 2005, but effective as of October
31, 2005, by and among SESI, L.L.C., CSI Technologies, LLC,
J.R.B. Consultants, Inc., SEMO, L.L.C., SEMSE, L.L.C.,
Snubbing Technology Services, LLC, Superior Canada Holding,
Inc., Universal Fishing and Rental Tools, Inc. and the Bank
of New York, as trustee (incorporated herein by reference to
Exhibit 4.1 to the Companys Form 8-K filed November 15,
2005), as amended by Sixth Supplemental Indenture, dated as
of May 19, 2006, by and among SESI, L.L.C. and The Bank of
New York Trust Company, N.A., as trustee (incorporated
herein by reference to Exhibit 4.1 to the Companys Form 8-K
filed May 23, 2006). |
|
|
|
4.3
|
|
Indenture, dated May 22, 2006, among the Company, SESI,
L.L.C., the guarantors identified therein and The Bank of
New York Trust Company, N.A., as trustee (incorporated
herein by reference to Exhibit 4.2 to the Companys Form 8-K
filed May 23, 2006), as amended by Supplemental Indenture,
dated December 12, 2006, by and among Warrior Energy
Services Corporation, SESI, L.L.C., the other Guarantors (as
defined in the Indenture referred to therein) and The Bank
of New York Trust Company, N.A., as trustee (incorporated
herein by reference to Exhibit 4.1 to the Companys 8-K
filed December 13, 2006 for the period beginning December
12, 2006). |
|
|
|
4.4
|
|
Indenture, dated December 12, 2006, by and among the
Company, SESI, L.L.C., the guarantors named therein and The
Bank of New York Trust Company, N.A., as trustee
(incorporated herein by reference to Exhibit 4.1 to the
Companys Form 8-K filed December 13, 2006 for the period
beginning December 7, 2006), as amended by Supplemental
Indenture, dated December 12, 2006, by and among Warrior
Energy Services Corporation, SESI, L.L.C., the other
Guarantors (as defined in the Indenture referred to therein)
and The Bank of New York Trust Company, N.A., as trustee
(incorporated herein by reference to Exhibit 4.2 to the
Companys Form 8-K filed December 13, 2006 for the period
beginning December 12, 2006). |
|
|
|
10.1
|
|
Amended and Restated Superior Energy Services, Inc. 1995
Stock Incentive Plan (incorporated herein by reference to
Exhibit A to the Companys Definitive Proxy Statement dated
June 25, 1997). |
83
|
|
|
Exhibit No. |
|
Description |
10.2
|
|
Superior Energy Services, Inc. 1999 Stock Incentive Plan
(incorporated herein by reference to the Companys Annual
Report on Form 10-K for the year ended December 31, 1999),
as amended by Second Amendment to Superior Energy Services,
Inc. 1999 Stock Incentive Plan, effective as of December 7,
2004 (incorporated herein by reference to Exhibit 10.2 to
the Companys Form 8-K filed on December 20, 2004). |
|
|
|
10.3
|
|
Employment Agreement between the Company and Terence E. Hall
(incorporated herein by reference to the Companys Annual
Report on Form 10-K for the year ended December 31, 1999),
as amended by Letter Agreement dated November 12, 2004
between the Company and Terence E. Hall (incorporated herein
by reference to Exhibit 10.1 to the Companys Form 8-K filed
on November 15, 2004). |
|
|
|
10.4
|
|
Amended and Restated Superior Energy Services, Inc. 2002
Stock Incentive Plan (incorporated herein by reference to
the Companys Annual Report on Form 10-K for the year ended
December 31, 2003), as amended by First Amendment to
Superior Energy Services, Inc. 2002 Stock Incentive Plan,
effective as of December 7, 2004 (incorporated herein by
reference to Exhibit 10.1 to the Companys Form 8-K filed on
December 20, 2004). |
|
|
|
10.5
|
|
Form of Employment Agreement executed between the Company
and each of its Chief Operating Officer and its Chief
Financial Officer (incorporated herein by reference to
Exhibit 10.1 to the Companys Form 8-K filed on February 25,
2005). |
|
|
|
10.6
|
|
Form of Employment Agreement executed between the Company
and each of its Executive Officers other than its Chairman
and Chief Executive Officer, its Chief Operating Officer and
its Chief Financial Officer (incorporated herein by
reference to Exhibit 10.2 to the Companys Form 8-K filed on
February 25, 2005). |
|
|
|
10.7
|
|
Superior Energy Services, Inc. Nonqualified Deferred
Compensation Plan (incorporated herein by reference to the
Companys Annual Report on Form 10-K for the year ended
December 31, 2004). |
|
|
|
10.8
|
|
Superior Energy Services, Inc. 2005 Stock Incentive Plan
(incorporated herein by reference to Appendix A to the
Companys Definitive Proxy Statement dated April 18, 2005). |
|
|
|
10.9
|
|
Amended and Restated Credit Agreement, dated October 31,
2005, by and among SESI, L.L.C., as borrower, the Company,
as parent, JPMorgan Chase Bank, N.A., successor by merger
with Bank One, NA, as agent, Wells Fargo Bank, N.A.,
successor by merger with Wells Fargo Bank Texas, N.A., as
syndication agent, Whitney National Bank, as documentation
agent, and the lenders party hereto (incorporated herein by
reference to Exhibit 10.1 to the Companys Form 8-K filed
November 3, 2005), as amended by First Amendment to Amended
and Restated Credit Agreement, dated May 3, 2006
(incorporated herein by reference to Exhibit 10.1 to the
Companys Form 8-K filed May 9, 2006). |
|
|
|
10.10
|
|
Amended and Restated Superior Energy Services, Inc. 2004
Directors Restricted Stock Units Plan (incorporated herein
by reference to Appendix B to the Companys Definitive Proxy
Statement dated April 20, 2006). |
84
|
|
|
Exhibit No. |
|
Description |
10.11
|
|
Purchase and Sale Agreement, dated May 15, 2006, by and
between Noble Energy, Inc. and Coldren Resources LP
(incorporated herein by reference to Exhibit 10.1 to the
Companys Form 8-K filed May 17, 2006). |
|
|
|
10.12
|
|
Purchase Agreement, dated May 17, 2006, by and among SESI,
L.L.C., the guarantors identified therein, Bear, Stearns &
Co. Inc., J.P. Morgan Securities Inc., Howard Weil
Incorporated, Johnson Rice & Company L.L.C., Pritchard
Capital Partners, LLC, Raymond James & Associates, Inc. and
Simmons & Company International (incorporated herein by
reference to Exhibit 10.1 to the Companys Form 8-K filed
May 23, 2006). |
|
|
|
10.13
|
|
Registration Rights Agreement, dated May 22, 2006, by and
among SESI, L.L.C., the guarantors identified therein, ,
Bear, Stearns & Co. Inc., J.P. Morgan Securities Inc.,
Howard Weil Incorporated, Johnson Rice & Company L.L.C.,
Pritchard Capital Partners, LLC, Raymond James & Associates,
Inc. and Simmons & Company International (incorporated
herein by reference to Exhibit 10.2 to the Companys Form
8-K filed May 23, 2006). |
|
|
|
10.14
|
|
Amended and Restated Credit Agreement, dated December 6,
2006, by and among the Company, SESI, L.L.C., JPMorgan Chase
Bank, N.A., and the lenders party thereto (incorporated
herein by reference to Exhibit 10.1 to the Companys Form
8-K filed December 7, 2006). |
|
|
|
10.15
|
|
Registration Rights Agreement, dated December 12, 2006, by
and among the Company, SESI, L.L.C., the guarantors named
therein, Bear, Stearns & Co. Inc., Lehman Brothers Inc. and
JPMorgan Securities Inc. (incorporated herein by reference
to Exhibit 10.2 to the Companys Form 8-K filed December 13,
2006 for the period beginning December 7, 2006). |
|
|
|
10.16
|
|
Confirmation of OTC Exchangeable Note Hedge, dated December
7, 2006, by and between SESI, L.L.C. and Bear, Stearns
International, Limited (incorporated herein by reference to
Exhibit 10.3 to the Companys Form 8-K filed December 13,
2006 for the period beginning December 7, 2006). |
|
|
|
10.17
|
|
Confirmation of OTC Exchangeable Note Hedge, dated December
7, 2006, by and between SESI, L.L.C. and Lehman Brothers OTC
Derivatives Inc. (incorporated herein by reference to
Exhibit 10.4 to the Companys Form 8-K filed December 13,
2006 for the period beginning December 7, 2006). |
|
|
|
10.18
|
|
Confirmation of OTC Warrant Confirmation, dated December 7,
2006, by and between the Company and Bear, Stearns
International, Limited (incorporated herein by reference to
Exhibit 10.5 to the Companys Form 8-K filed December 13,
2006 for the period beginning December 7, 2006). |
85
|
|
|
Exhibit No. |
|
Description |
10.19
|
|
Confirmation of OTC Warrant Confirmation, dated December 7,
2006, by and between the Company and Lehman Brothers OTC
Derivatives Inc. (incorporated herein by reference to
Exhibit 10.6 to the Companys Form 8-K filed December 13,
2006 for the period beginning December 7, 2006). |
|
|
|
10.20
|
|
Form of Performance Share Unit Award Agreement (incorporated
herein by reference to Exhibit 10.1 to the Companys Form
8-K filed December 20, 2006). |
|
|
|
10.21
|
|
Form of Stock Option Agreement for the grant of
non-qualified stock options under the Superior Energy
Services, Inc. 2005 Stock Incentive Plan (incorporated
herein by reference to Exhibit 10.2 to the Companys Form
8-K filed December 20, 2006). |
|
|
|
10.22
|
|
Form of Restricted Stock Agreement (incorporated herein by
reference to Exhibit 10.3 to the Companys Form 8-K filed
December 20, 2006). |
|
|
|
14.1
|
|
Code of business ethics and conduct (incorporated herein by
reference to the Companys Annual Report on Form 10-K for
the year ended December 31, 2003). |
|
|
|
21.1*
|
|
Subsidiaries of the Company. |
|
|
|
23.1*
|
|
Consent of KPMG LLP. |
|
|
|
23.2*
|
|
Consent of DeGolyer and MacNaughton. |
|
|
|
31.1*
|
|
Officers certification pursuant to Rules 13a-14(a) and
15d-14(a) under the Securities Exchange Act of 1934, as
amended. |
|
|
|
31.2*
|
|
Officers certification pursuant to Rules 13a-14(a) and
15d-14(a) under the Securities Exchange Act of 1934, as
amended. |
|
|
|
32.1*
|
|
Officers certification pursuant to Section 1350 of Title 18
of the U.S. Code. |
|
|
|
32.2*
|
|
Officers certification pursuant to Section 1350 of Title 18
of the U.S. Code. |
86
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.
|
|
|
|
|
|
SUPERIOR ENERGY SERVICES, INC.
|
|
|
|
|
Date: February 28, 2007 |
|
|
|
By: |
/s/ Terence E. Hall
|
|
|
|
Terence E. Hall |
|
|
|
Chairman of the Board and
Chief Executive Officer |
|
|
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.
|
|
|
|
|
Signature |
|
Title |
|
Date |
|
|
|
|
|
/s/ Terence E. Hall
|
|
Chairman of the Board and
|
|
February 28, 2007 |
|
|
Chief
Executive Officer (Principal Executive Officer) |
|
|
|
|
|
|
|
/s/ Robert S. Taylor
|
|
Executive Vice President, Treasurer and
|
|
February 28, 2007 |
|
|
Chief
Financial Officer
(Principal Financial and Accounting Officer) |
|
|
|
|
|
|
|
/s/ Harold J. Bouillion
|
|
Director
|
|
February 28, 2007 |
|
|
|
|
|
|
|
|
|
|
/s/ Enoch L. Dawkins
|
|
Director
|
|
February 28, 2007 |
|
|
|
|
|
|
|
|
|
|
/s/ James M. Funk
|
|
Director
|
|
February 28, 2007 |
|
|
|
|
|
|
|
|
|
|
/s/ Ernest E. Howard, III
|
|
Director
|
|
February 28, 2007 |
|
|
|
|
|
|
|
|
|
|
/s/ Richard A. Pattarozzi
|
|
Director
|
|
February 28, 2007 |
|
|
|
|
|
|
|
|
|
|
/s/ Justin L. Sullivan
|
|
Director
|
|
February 28, 2007 |
|
|
|
|
|
87
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Schedule II Valuation and Qualifying Accounts
Years Ended December 31, 2006, 2005 and 2004
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions |
|
|
|
|
|
|
|
|
Balance at the |
|
Charged to |
|
|
|
|
|
|
|
|
|
Balance |
|
|
beginning of |
|
costs and |
|
Balances from |
|
|
|
|
|
at the end |
Description |
|
the year |
|
expenses |
|
acquisitions |
|
Deductions |
|
of the year |
|
Year ended December 31, 2006: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts |
|
$ |
11,569 |
|
|
$ |
3,273 |
|
|
$ |
4,464 |
|
|
$ |
1,887 |
|
|
$ |
17,419 |
|
Year ended December 31, 2005: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts |
|
$ |
8,364 |
|
|
$ |
3,595 |
|
|
$ |
|
|
|
$ |
390 |
|
|
$ |
11,569 |
|
Year ended December 31, 2004: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts |
|
$ |
6,280 |
|
|
$ |
2,970 |
|
|
$ |
35 |
|
|
$ |
921 |
|
|
$ |
8,364 |
|
88
EXHIBIT
INDEX
|
|
|
Exhibit No. |
|
Description |
21.1*
|
|
Subsidiaries of the Company. |
|
|
|
23.1*
|
|
Consent of KPMG LLP. |
|
|
|
23.2*
|
|
Consent of DeGolyer and MacNaughton. |
|
|
|
31.1*
|
|
Officers certification pursuant to Rules 13a-14(a) and
15d-14(a) under the Securities Exchange Act of 1934, as
amended. |
|
|
|
31.2*
|
|
Officers certification pursuant to Rules 13a-14(a) and
15d-14(a) under the Securities Exchange Act of 1934, as
amended. |
|
|
|
32.1*
|
|
Officers certification pursuant to Section 1350 of Title 18
of the U.S. Code. |
|
|
|
32.2*
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Officers certification pursuant to Section 1350 of Title 18
of the U.S. Code. |
exv21w1
EXHIBIT 21.1
SUPERIOR ENERGY SERVICES, INC.
List of Subsidiaries
Pursuant to Item 601(b)(21)(ii) of Regulation S-K, the names of other subsidiaries of Superior
Energy Services, Inc. are omitted because, considered in the aggregate, they would not constitute a
significant subsidiary as of the end of the year covered by this report.
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STATE OF JURISDICTION |
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OF INCORPORATION OR |
NAME |
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ORGANIZATION |
1105 Peters Road, L.L.C.
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Louisiana |
Blowout Tools, Inc.
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Texas |
Concentric Pipe and Tool Rentals, L.L.C.
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Louisiana |
Connection Technology, L.L.C.
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Louisiana |
Duffy & McGovern Accommodation Services Limited
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United Kingdom |
Fastorq, L.L.C.
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Louisiana |
H.B. Rentals, L.C.
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Louisiana |
International Snubbing Services, L.L.C.
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Louisiana |
Premier Oilfield Rentals Limited
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Scotland |
Production Management Industries, L.L.C.
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Louisiana |
SES Canada, ULC
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Canada |
SESI, L.L.C.
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Delaware |
SPN Resources, LLC
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Louisiana |
Southeast Australian Services Pty., Ltd.
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Australia |
Stabil Drill Specialties, L.L.C.
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Louisiana |
Sub-Surface Tools, L.L.C.
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Louisiana |
Superior Energy Liftboats, L.L.C.
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Louisiana |
Superior Energy Services, L.L.C.
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Louisiana |
Superior Energy Services de Venezuela, C.A.
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Venezuela |
Superior Energy Services Trinidad Limited
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Trinidad/Tobago |
Superior Inspection Services, Inc.
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Louisiana |
Warrior Energy Services Corporation
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Delaware |
Wild Well Control, Inc.
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Texas |
Workstrings, L.L.C.
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Louisiana |
exv23w1
Exhibit 23.1
Consent of Independent Registered Public Accounting Firm
The Board of Directors
Superior Energy Services, Inc.:
We consent to incorporation by reference in Registration Statements No. 333-35286 and No. 33-123442
on Form S-3 and No. 333-12175, No. 333-43421, No. 333-33758, No. 333-101211, No. 333-125316, No.
333-136809, No. 333-116078 on Form S-8 of Superior Energy Services, Inc. of our reports dated
February 28, 2007, with respect to the consolidated balance sheets of Superior Energy Services,
Inc. and subsidiaries as of December 31, 2006 and 2005 and the related consolidated statements of
operations, changes in stockholders equity and cash flows for each of the years in the three-year
period ended December 31, 2006, the related consolidated financial statement schedule, managements
assessment of the effectiveness of internal control over financial reporting as of December 31,
2006, and the effectiveness of internal control over financial reporting as of December 31, 2006,
which reports appear in the December 31, 2006 annual report on Form 10-K of Superior Energy
Services, Inc.
Our Report for the year ended December 31, 2006 refers to a change in the method of accounting for
share-based payments.
/s/ KPMG LLP
New Orleans, Louisiana
February 28, 2007
exv23w2
EXHIBIT 23.2
DEGOLYER AND MACNAUGHTON
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244
February 27, 2007
Superior Energy Services, Inc.
1105 Peters Road
Harvey, LA 70058
Ladies and Gentlemen:
We hereby consent to the reference to DeGolyer and MacNaughton and to the incorporation of the
estimates contained in our Appraisal Report as of December 31, 2006 on Certain Properties owned by
SPN Resources, LLC (our Report) in Part 1, General Business Description, Oil and Natural Gas
Reserves and in the Notes to the Consolidated Financial Statements portion of the Annual Report
on Form 10-K of Superior Energy Services, Inc. for the year ended December 31, 2006. SPN
Resources, LLC is a wholly owned subsidiary of Superior Energy Services, Inc. In addition, we
hereby consent to the incorporation by reference of references to DeGolyer and MacNaughton and to
our Report in Superior Energy Services, Inc.s Registration Statements on Form S-3 (Registration
Nos. 333-123442 and No. 333-35286) and on Form S-8 (Registration Nos. 333-125316, 333-116078,
333-101211, 333-33758, 333-43421, 333-12175, and 333-136809).
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Very truly yours, |
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/s/ DeGOLYER and MacNAUGHTON |
exv31w1
EXHIBIT 31.1
CERTIFICATION PURSUANT TO
RULES 13a-14(a) AND 15d-14(a) UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED
I, Terence E. Hall, Chairman of the Board and Chief Executive Officer of Superior Energy
Services, Inc., certify that:
1. |
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I have reviewed this annual report on Form 10-K of Superior Energy Services, Inc.; |
2. |
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Based on my knowledge, this report does not contain any untrue statement of a material fact
or omit to state a material fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading with respect to the period
covered by this report; |
3. |
|
Based on my knowledge, the financial statements, and other financial information included in
this report, fairly present in all material respects the financial condition, results of
operations and cash flows of the registrant as of, and for, the periods presented in this
report; |
4. |
|
The registrants other certifying officer and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and
15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and have: |
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a) |
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Designed such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure that material
information relating to the registrant, including its consolidated subsidiaries, is
made known to us by others within those entities, particularly during the period in
which this report is being prepared; |
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b) |
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Designed such internal control over financial reporting, or caused such
internal control over financial reporting to be designed under our supervision, 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; |
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c) |
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Evaluated the effectiveness of the registrants disclosure controls and
procedures and presented in this report our conclusions about the effectiveness of the
disclosure controls and procedures, as of the end of the period covered by this report
based on such evaluation; and |
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d) |
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Disclosed in this report any change in the registrants internal control over
financial reporting that occurred during the registrants most recent fiscal quarter
(the registrants fourth fiscal quarter in the case of an annual report) that has
materially affected, or is reasonably likely to materially affect, the registrants
internal control over financial reporting; and |
5. |
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The registrants other certifying officer and I have disclosed, based on our most recent
evaluation of internal control over financial reporting, to the registrants auditors and the
audit committee of registrants board of directors (or persons performing the equivalent
functions): |
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a) |
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All significant deficiencies and material weaknesses in the design or operation
of internal control over financial reporting which are reasonably likely to adversely
affect the registrants ability to record, process, summarize and report financial
information; and |
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b) |
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Any fraud, whether or not material, that involves management or other employees
who have a significant role in the registrants internal control over financial
reporting. |
Date: February 28, 2007
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/s/ Terence E. Hall
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Terence E. Hall |
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Chairman of the Board and Chief Executive Officer
Superior Energy Services, Inc. |
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exv31w2
EXHIBIT 31.2
CERTIFICATION PURSUANT TO
RULES 13a-14(a) AND 15d-14(a) UNDER THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED
I, Robert S. Taylor, Executive Vice President, Treasurer and Chief Financial Officer of
Superior Energy Services, Inc., certify that:
1. |
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I have reviewed this annual report on Form 10-K of Superior Energy Services, Inc.; |
2. |
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Based on my knowledge, this report does not contain any untrue statement of a material fact
or omit to state a material fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading with respect to the period
covered by this report; |
3. |
|
Based on my knowledge, the financial statements, and other financial information included in
this report, fairly present in all material respects the financial condition, results of
operations and cash flows of the registrant as of, and for, the periods presented in this
report; |
4. |
|
The registrants other certifying officer and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and
15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and have: |
|
a) |
|
Designed such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to ensure that material
information relating to the registrant, including its consolidated subsidiaries, is
made known to us by others within those entities, particularly during the period in
which this report is being prepared; |
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b) |
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Designed such internal control over financial reporting, or caused such
internal control over financial reporting to be designed under our supervision, 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; |
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c) |
|
Evaluated the effectiveness of the registrants disclosure controls and
procedures and presented in this report our conclusions about the effectiveness of the
disclosure controls and procedures, as of the end of the period covered by this report
based on such evaluation; and |
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d) |
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Disclosed in this report any change in the registrants internal control over
financial reporting that occurred during the registrants most recent fiscal quarter
(the registrants fourth fiscal quarter in the case of an annual report) that has
materially affected, or is reasonably likely to materially affect, the registrants
internal control over financial reporting; and |
5. |
|
The registrants other certifying officer and I have disclosed, based on our most recent
evaluation of internal control over financial reporting, to the registrants auditors and the
audit committee of registrants board of directors (or persons performing the equivalent
functions): |
|
a) |
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All significant deficiencies and material weaknesses in the design or operation
of internal control over financial reporting which are reasonably likely to adversely
affect the registrants ability to record, process, summarize and report financial
information; and |
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b) |
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Any fraud, whether or not material, that involves management or other employees
who have a significant role in the registrants internal control over financial
reporting. |
Date: February 28, 2007
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/s/ Robert S. Taylor
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Robert S. Taylor |
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Executive Vice President, Treasurer and Chief
Financial Officer
Superior Energy Services, Inc. |
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exv32w1
EXHIBIT 32.1
CERTIFICATION PURSUANT TO
SECTION 1350 OF TITLE 18 OF THE U.S. CODE
I, Terence E. Hall, Chairman of the Board and Chief Executive Officer of Superior Energy Services,
Inc. (the Company), certify, pursuant to Section 1350 of Title 18 of the U.S. Code, adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Section 906), that:
1. |
|
the annual report on Form 10-K of the Company for the year ended December 31, 2006 (the
Report), as filed with the Securities and Exchange Commission on the date hereof, fully
complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of
1934; and |
2. |
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the information contained in the Report fairly presents, in all material respects, the
financial condition and results of operations of the Company. |
This certificate is being furnished solely for purposes of Section 906 and is not being filed as
part of the Report or as a separate disclosure document.
Date: February 28, 2007
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/s/ Terence E. Hall
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Terence E. Hall |
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Chairman of the Board and Chief Executive Officer
Superior Energy Services, Inc. |
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A signed original of this written statement required by Section 906 has been provided to the
Company and will be retained by the Company and furnished to the Securities and Exchange Commission
or its staff upon request.
exv32w2
EXHIBIT 32.2
CERTIFICATION PURSUANT TO
SECTION 1350 OF TITLE 18 OF THE U.S. CODE
I, Robert S. Taylor, Executive Vice President, Treasurer and Chief Financial Officer of Superior
Energy Services, Inc. (the Company), certify, pursuant to Section 1350 of Title 18 of the U.S.
Code, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Section 906), that:
1. |
|
the annual report on Form 10-K of the Company for the year ended December 31, 2006 (the
Report), as filed with the Securities and Exchange Commission on the date hereof, fully
complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of
1934; and |
2. |
|
the information contained in the Report fairly presents, in all material respects, the
financial condition and results of operations of the Company. |
This certificate is being furnished solely for purposes of Section 906 and is not being filed as
part of the Report or as a separate disclosure document.
Date: February 28, 2007
|
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/s/ Robert S. Taylor
|
|
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Robert S. Taylor |
|
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Executive Vice President, Treasurer and Chief
Financial Officer
Superior Energy Services, Inc. |
|
|
A signed original of this written statement required by Section 906 has been provided to the
Company and will be retained by the Company and furnished to the Securities and Exchange Commission
or its staff upon request.