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 |
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For the fiscal year ended December 31, 2005 |
or
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Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
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For the Transition Period from
to
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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 |
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(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 |
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(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 |
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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: |
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. þ
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of
the Exchange Act). Yes þ No 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. (Check one):
Large
accelerated filer o Accelerated filer o Non-accelerated filer 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,
2005 based on the closing price on the New York Stock Exchange on that date was $1,416,844,000.
The number of shares of the registrants common stock outstanding on February 28, 2006 was
79,732,091.
DOCUMENTS INCORPORATED BY REFERENCE
Certain information called for by Item 5 of Part II and 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, 2005
TABLE OF CONTENTS
(i)
FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K contains forward-looking statements that are subject to a number of
risks and uncertainties. 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 actions, industry trends, 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 such 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.
The forward-looking statements are made pursuant to the safe harbor provisions of the Private
Securities Litigation Reform Act of 1995. Numerous factors could cause actual results to differ
materially from those in the forward-looking statements, including those described under Item 1A.
Risk Factors below and elsewhere herein.
PART I
Item 1. Business
General
We are a leading provider of specialized oilfield services and equipment focused 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,
marine and other oilfield services segments. In recent years, we have expanded geographically so
that we now also have a growing presence in select domestic land and international markets. We
also own and operate, through our subsidiary SPN Resources, LLC, mature oil and gas properties in
the Gulf of Mexico. Our business is organized into five segments consisting of well intervention
services, rental tools, marine services, other oilfield services and oil and gas operations. We
believe that we are one of the few companies in the Gulf of Mexico 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
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.
SPN Resources acquires mature, shallow water Gulf of Mexico oil and gas properties from our
customers. We believe this service provides our customers with an effective way to dispose of
older, non-core properties that provides additional utilization for our well intervention and
decommissioning services and our platform management business. We use our production-related
services to enhance production and, at the end of a propertys economic life, use our assets to
plug wells and decommission properties. Since we operate virtually all of the properties we own,
we can schedule work to increase our efficiency and the utilization of our assets and services.
Operations
Well Intervention Services. We provide well intervention services that stimulate oil and
gas production using platforms or our liftboats rather than through the use of a drilling rig,
which we believe provides a cost advantage to our customers. Our well intervention services
include coiled tubing, electric wireline, mechanical wireline, pumping and stimulation, artificial
lift, well control, snubbing, recompletion, engineering and well evaluation services. We believe
we are the leading provider of mechanical wireline services in the Gulf of Mexico with
approximately 190 offshore wireline units, 20 land wireline units and 10 dedicated liftboats
configured specifically for wireline services. We also perform both permanent and temporary plug
and abandonment services and decommissioning services. We are constructing an 880-ton derrick barge to support SPN Resources
business and to expand our decommissioning services. We expect the barge to be available late in
the third quarter of 2006.
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
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internal growth and acquisitions, we have increased
the size and breadth of our rental tool inventory and now have 28 locations in all major staging
points in Louisiana and Texas for offshore oil and gas activities in the Gulf of Mexico. Our
rental tool segment also has locations domestically in North Louisiana, Oklahoma and Wyoming, and
internationally in Venezuela, Trinidad, Mexico, Eastern Canada, the North Sea, the Middle East and
West Africa. Our rental tools include pressure control equipment, specialty tubular goods,
connecting iron, handling tools, drill pipe, bolting equipment, power swivels, 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 36 liftboats,
including 10 liftboats configured specifically for wireline services (included in our well
intervention segment) and 26 in our rental fleet with leg-lengths ranging from 145 feet to 250
feet. In June 2005, we sold our 17 rental liftboats in the 105-foot and the 120 to 135-foot
classes since we believed they were not core to our production-related services and decommissioning
strategies. We are also currently refurbishing a 200-foot class liftboat and anticipate returning
it to service during the second quarter of 2006. 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 will reposition some of our larger liftboats to
international market areas if opportunities arise.
Other Oilfield Services. We provide a broad range of platform and field management
services to the offshore and onshore oil and gas industry, including property management,
engineering services, operating labor, transportation, tools and supplies, technical supervision,
maintenance, supplemental personnel, and logistics services. We currently provide property
management services to approximately 130 offshore facilities in the Gulf of Mexico. We also
provide environmental cleaning services, including tank and vessel cleaning and safe vessel entry.
We also provide other services, including the manufacture and sale of specialized drilling rig
instrumentation, electronic torque and pressure control equipment. Subsequent to year-end, we sold
our non-hazardous oilfield waste management business, as it was not core to our production-related
services.
Oil and Gas Operations. We acquire mature oil and gas properties in the Gulf of Mexico to
provide our customers a cost-effective alternative to the 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, 2005, we had interests in 32 offshore blocks containing 58 structures and approximately 140
producing wells.
For additional industry segment financial information, see note 14 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 operating on the
U.S. continental shelf. Sales to Shell accounted for approximately 10% of our total revenue in
2005. In 2004, no customer accounted for more than 10% of revenue and in 2003, sales to one
customer accounted for approximately 11% of our total 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 segments in which we operate, including well intervention and other
oilfield services. 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 smaller companies that provide liftboat
services. 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 environmental accidents,
personal injury and damage or loss of equipment. 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. |
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 relatively standardized
terms. These leases 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 of 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 Natural Gas Act of 1938, the Natural Gas Policy Act of 1978, and Federal
Energy Regulatory Commission, or FERC, regulations. The Natural Gas Wellhead Decontrol Act,
enacted effective January 1, 1993, deregulated the price for all first sales of natural gas.
Thus, all of our sales of gas 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.
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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 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. Similarly, and despite the recent trend toward federal deregulation of
the natural gas industry, whether or to what extent that trend will continue, or what the ultimate
effect will be on our sales of gas, cannot be predicted.
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 operating and disposal
practices that were standard in the
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industry at the time they may have been utilized, 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 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 for job related injuries, with generally no limitations on
our potential liability.
Employees
As of February 28, 2006, we had approximately 3,200 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.
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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 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 76 facilities located in Louisiana, Texas, Oklahoma, Colorado, Wyoming,
Venezuela, Australia, Trinidad, Mexico, the North Sea, Eastern Canada, the Middle East and West
Africa 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,
2005 and 2004 and estimated future net revenues and cash flows attributable thereto. Our proved
reserves for 2005 and 2004 were estimated by DeGolyer and MacNaughton, independent petroleum
engineers. Our proved reserves at December 31, 2003 were not significant.
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As of December 31, |
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2005 |
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2004 |
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Total estimated net proved reserves: |
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Oil (Mbbls) |
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9,103 |
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9,120 |
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Natural gas (Mmcf) |
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23,688 |
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29,380 |
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Total (Mboe) (1) |
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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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7,554 |
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7,731 |
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Natural gas (Mmcf) |
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21,703 |
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25,542 |
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Total (Mboe) (1) |
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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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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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$ |
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, 2005 amount was estimated by DeGolyer and MacNaughton using a period-end crude
New York Mercantile Exchange (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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(3) |
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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, 2005 were 3,713 mbbls (41% of total
net proved oil reserves) and 16,469 mmcf (70% of total net proved gas reserves). Net proved
undeveloped reserves as of December 31, 2005 were 1,549 mbbls (17.0% of total net proved oil
reserves) and 1,985 mmcf (8.4% 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, 2005, of productive oil and natural gas
wells. Productive wells consist of producing wells and wells capable of production. Thirteen
gross oil wells and two 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 |
|
|
293.00 |
|
|
|
286.10 |
|
Natural gas |
|
|
53.00 |
|
|
|
46.33 |
|
|
|
|
|
|
|
|
Total |
|
|
346.00 |
|
|
|
332.43 |
|
|
|
|
|
|
|
|
As of December 31, 2005, only approximately 140 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, 2005 relating to acreage held by us.
Developed acreage is assigned to productive wells.
8
|
|
|
|
|
|
|
|
|
|
|
Gross |
|
|
Net |
|
|
|
Acreage |
|
|
Acreage |
|
Developed |
|
|
133,387 |
|
|
|
110,458 |
|
Undeveloped |
|
|
5,760 |
|
|
|
5,760 |
|
|
|
|
|
|
|
|
Total |
|
|
139,147 |
|
|
|
116,218 |
|
|
|
|
|
|
|
|
Leases covering 100% of our undeveloped net acreage will expire in 2006.
Drilling Activity
The following table shows our drilling activity for the years ended December 31, 2005, 2004 and
2003. 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
2004 |
|
2003 |
|
|
Gross |
|
Net |
|
Gross |
|
Net (1) |
|
Gross |
|
Net |
Development Wells: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive |
|
|
1.00 |
|
|
|
0.50 |
|
|
|
3.00 |
|
|
|
0.06 |
|
|
|
0.00 |
|
|
|
0.00 |
|
Non-productive |
|
|
0.00 |
|
|
|
0.00 |
|
|
|
0.00 |
|
|
|
0.00 |
|
|
|
0.00 |
|
|
|
0.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
1.00 |
|
|
|
0.50 |
|
|
|
3.00 |
|
|
|
0.06 |
|
|
|
0.00 |
|
|
|
0.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
These wells were proposed and drilled under the supervision of our exploitation partner in an
offshore lease in which we have only a 2% working interest. |
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, 2005, 2004 and 2003 (in thousands). We
acquired our first property in December 2003.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
Acquisition of properties proved |
|
$ |
9,015 |
|
|
$ |
81,356 |
|
|
$ |
5,041 |
|
Development costs |
|
|
19,867 |
|
|
|
4,707 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred |
|
$ |
28,882 |
|
|
$ |
86,063 |
|
|
$ |
5,041 |
|
|
|
|
|
|
|
|
|
|
|
Capitalized costs for oil and gas producing activities consist of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
Proved properties |
|
$ |
28,882 |
|
|
$ |
86,063 |
|
|
$ |
5,041 |
|
Accumulated depreciation, depletion and amortization |
|
|
(18,065 |
) |
|
|
(7,156 |
) |
|
|
(131 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
10,817 |
|
|
$ |
78,907 |
|
|
$ |
4,910 |
|
|
|
|
|
|
|
|
|
|
|
9
Intellectual Property
We use several patented items in our operations that we believe are important but are 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.
Other Information
We have our principal executive offices at 1105 Peters Road, Harvey, Louisiana. 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/ .
Item 1A. Risk Factors
There are many factors that affect our business and the results of our operations, many of which
are beyond our control. If any of the following risks develop into actual events, our business,
financial condition, results of operations or cash flows could be adversely affected and the
trading price of our common stock could decline.
We are subject to the cyclical nature of the oil and gas industry.
Our business depends primarily on the level of activity by the oil and gas companies in the Gulf of
Mexico and along the Gulf Coast. This level of activity has traditionally been volatile as a
result of fluctuations in oil and gas prices and their uncertainty in the future. The purchases of
the products and services we provide are, to a substantial extent, deferrable in the event oil and
gas companies reduce capital expenditures. Therefore, the willingness of our customers to make
expenditures is critical to our operations. The levels of such capital expenditures are influenced
by:
|
|
|
oil and gas prices and industry perceptions of future price levels; |
|
|
|
|
the cost of exploring for, producing and delivering oil and gas; |
|
|
|
|
the ability of oil and gas companies to generate capital; |
|
|
|
|
the sale and expiration dates of offshore leases; |
|
|
|
|
the discovery rate of new oil and gas reserves; and |
|
|
|
|
local and international political and economic conditions. |
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 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 |
|
|
|
|
governmental regulation. |
10
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.
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 us or 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.
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. In addition, we acquire these properties without obtaining
bonds, other than as required by MMS to secure the plugging and abandonment obligations.
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 older and near the end of their economic lives, 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.
11
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 may not be able to obtain future insurance coverage comparable with that of prior
years, thus putting us at a greater risk of loss due to severe weather conditions. We are also
likely to experience increased cost for available insurance coverage which will likely impose
higher deductibles and limit maximum aggregate recoveries for certain perils such as hurricane
related windstorm damage or loss. Any significant uninsured losses could have a material adverse
effect on our financial position, results of operations and cash flows.
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 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 2005, Shell accounted for approximately 10% of our total revenue. We did not
have a single customer account for more than 10% of our total revenue in 2004 and in 2003, sales to
a single customer accounted for approximately 11% of our total revenue. 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; |
|
|
|
|
well blowouts; |
|
|
|
|
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 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 state workers
compensation laws inapplicable to these employees and instead permit
12
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 these operations are $50 million per occurrence for well control incidents,
and the limit is also $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 expect
very substantial increases in our costs of insurance, as well as increased deductibles and
self-insured retentions. We also expect that upon renewal, this property insurance coverage will
be subject to an annual loss limit of $35 million in the aggregate with respect to property damage
caused by hurricanes and named storms. We are seeking alternatives to allow us to increase this
annual aggregate limit. Any significant uninsured losses could have a material adverse effect on
our financial position, results of operations and cash flows.
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 may
not be able to obtain future insurance coverage comparable with that of prior years, thus putting
us at a greater risk of loss due to severe weather conditions. In addition, we are likely to
experience increased cost for available insurance coverage which may impose higher deductibles and
limit maximum aggregate recoveries for certain perils such as hurricane related windstorm damage or
loss. As a result, we may be forced to modify our risk management program in response to changes
in the insurance market, including increased risk retention. 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. |
Oil and gas prices are volatile, and low prices could have a material adverse impact on our
business.
Our revenues, profitability and future growth and the carrying value of our oil and gas properties
depend substantially on the prices we realize for our production. Our realized prices also affect
the amount of cash flow available for capital expenditures and our ability to borrow and raise
additional capital.
Historically, the markets for oil and gas have been volatile, and they are likely to continue to be
volatile in the future. Among the factors that can cause this volatility are:
13
|
|
|
worldwide or regional demand for energy, which is affected by economic conditions; |
|
|
|
|
the domestic and foreign supply of oil and gas; |
|
|
|
|
weather conditions; |
|
|
|
|
domestic and foreign governmental regulations; |
|
|
|
|
political conditions in oil and gas producing regions; |
|
|
|
|
the ability of members of the Organization of Petroleum Exporting Countries to agree
upon and maintain oil prices and production levels; and |
|
|
|
|
the price and availability of alternative fuel sources. |
It is impossible to predict oil and gas price movements with certainty. Lower oil and gas prices
may not only decrease our revenues on a per unit basis but also may reduce the amount of oil and
gas that we can
produce economically. A substantial or extended decline in oil or gas prices may materially and
adversely affect our future business, financial condition, results of operations, liquidity and
ability to finance planned capital expenditures. Further, oil prices and gas prices do not
necessarily move together.
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.
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.
14
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.
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 and also may issue equity securities in connection with such
acquisitions. Such additional debt service requirements may impose a significant burden on our
results of operations and financial condition. The issuance of additional equity securities could
result in significant dilution to our stockholders. 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.
The nature of our industry subjects us to compliance with regulatory and environmental laws.
Our business is significantly affected by state and federal laws and other 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, and by changes in and the level of enforcement of such laws.
The production of oil and gas is subject to regulation under a wide range of local, state and
federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations
require permits for drilling operations, drilling bonds and plugging and abandonment and reports
concerning operations.
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.
The failure to comply with these rules and regulations can result in substantial penalties. The
regulatory burden on the oil and natural gas industry increases our cost of doing business and,
consequently, affects our profitability.
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 U.S. 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 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.
15
We have 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 had no material adverse effect on our
operations. However, such environmental laws are changed frequently. Sanctions for noncompliance
may include revocation of permits, corrective action orders, administrative or civil penalties and
criminal prosecution. We are unable to predict whether environmental laws will materially
adversely affect our future operations and financial results.
Federal and state laws that 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.
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 U.S. may
adversely affect the U.S. 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.
We will be subject to additional political, economic, and other uncertainties as we expand our
international operations.
A key element of our business strategy is to continue our international expansion into
international oil and gas producing areas such as Mexico, Trinidad, Venezuela, West Africa, the
Middle East, Australia, Eastern Canada and the North Sea. Our international operations are subject
to a number of risks inherent in any business operating in foreign countries including, but not
limited to:
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political, social and economic instability; |
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potential seizure or nationalization of assets; |
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increased operating costs; |
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modification or renegotiating of contracts; |
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import-export quotas; |
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currency fluctuations; and |
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other forms of government regulation which are beyond our control. |
Our operations have not yet been affected to any significant extent by such conditions or events,
but as our international operations expand, the exposure to these risks will increase. We could,
at any one time, have a significant amount of our revenues generated by operating activity in a
particular country. Therefore, our results of
16
operations could be susceptible to adverse events
beyond our control that could occur in the particular country in which we are conducting such
operations. We anticipate that our contracts to provide services internationally will generally
provide for payment in U.S. dollars and that we will not make significant investments in foreign
facilities. To the extent we make investments in foreign facilities or receive revenues in
currencies other than U.S. dollars, the value of our assets and our income could be adversely
affected by fluctuations in the value of local currencies.
Additionally, our competitiveness in international market areas may be adversely affected by
regulations, including, but not limited to, regulations requiring:
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the awarding of contracts to local contractors; |
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the employment of local citizens; and |
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the establishment of foreign subsidiaries with significant ownership positions reserved
by the foreign government for local citizens. |
We cannot predict what types of the above events may occur.
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 the Gulf Coast region 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
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 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.
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 13 to our
consolidated financial statements included in Item 8 of this Form 10-K.
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.
17
Item 4A. Executive Officers of Registrant
Terence E. Hall, age 60, 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 56, 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 51, 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 48, has served 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 37, has served as one of our Executive Vice Presidents since September 2004.
He has also served as a Vice President of our wholly owned subsidiary Superior Energy Services,
L.L.C. 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 48, 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. Since July 1999, Mr.
Holleman has served as a Vice President 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 48, has served as one of our Executive Vice Presidents since September 2004.
He also serves as the President of our wholly-owned subsidiary SPN Resources, LLC, which position
he has held 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 50, has served as one of our Executive Vice Presidents since September 2004.
He has also served as Vice President of Health, Safety and Environment and Corporate Services of
Superior Energy Services, L.L.C. from January 2002 to May 2005. Prior to joining us, Mr. Young
worked for 22 years at BP Amoco.
18
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.
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High |
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Low |
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2004 |
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First Quarter |
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$ |
10.95 |
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$ |
8.98 |
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Second Quarter |
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11.30 |
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8.65 |
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Third Quarter |
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12.93 |
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9.98 |
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Fourth Quarter |
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15.73 |
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11.95 |
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2005 |
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First Quarter |
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$ |
19.75 |
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$ |
14.58 |
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Second Quarter |
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18.46 |
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13.71 |
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Third Quarter |
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24.10 |
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17.64 |
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Fourth Quarter |
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23.98 |
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17.33 |
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As of February 28, 2006, there were 79,732,091 shares of our common stock outstanding, which were
held by 127 record holders.
Dividend Information
We do not plan to pay cash dividends on our common stock. We intend to retain all of the cash our
business generates to meet our working capital requirements and fund future growth. In addition,
our bank credit facility prevents us from paying dividends or making other distributions to our
stockholders.
Equity Compensation Plan Information
Information required by this item with respect to compensation plans under which our equity
securities are authorized for issuance will be contained in our definitive proxy statement to be
filed pursuant to Regulation 14A and is incorporated herein by reference.
Issuer Purchases of Equity Securities
None.
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.
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Years Ended December 31, |
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2005 |
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2004 |
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2003 |
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2002 |
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2001 |
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Revenues |
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$ |
735,334 |
(1) |
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$ |
564,339 |
(2) |
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$ |
500,625 |
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$ |
443,147 |
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$ |
449,042 |
(3) |
Income from operations |
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125,603 |
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76,289 |
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67,343 |
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57,021 |
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104,953 |
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Income before cumulative effect
of change in accounting principle |
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67,859 |
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35,852 |
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30,514 |
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21,886 |
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51,187 |
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Cumulative effect of change in
accounting principle, net |
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2,589 |
(4) |
Net income |
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67,859 |
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35,852 |
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30,514 |
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21,886 |
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53,776 |
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Net income before cumulative
effect of change in accounting principle per share: |
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Basic |
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0.87 |
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0.48 |
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0.41 |
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0.30 |
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0.74 |
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Diluted |
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0.85 |
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0.47 |
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0.41 |
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0.30 |
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0.73 |
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Net income per share: |
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Basic |
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0.87 |
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0.48 |
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0.41 |
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0.30 |
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0.78 |
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Diluted |
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0.85 |
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0.47 |
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0.41 |
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0.30 |
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0.77 |
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Total assets |
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1,097,250 |
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1,003,913 |
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832,863 |
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727,620 |
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665,520 |
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Long-term debt, less current portion |
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216,596 |
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244,906 |
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255,516 |
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256,334 |
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269,633 |
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Decommissioning liabilities,
less current portion |
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107,641 |
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90,430 |
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18,756 |
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Stockholders equity |
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524,374 |
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433,879 |
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368,129 |
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335,342 |
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269,576 |
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(1) |
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In the year ended December 31, 2005, our subsidiary, SPN Resources, LLC, acquired additional
oil and gas properties through the acquisition of interests in 3 offshore Gulf of Mexico
leases. Under the terms of the transaction, we received approximately $3.7 million in cash,
acquired the properties and assumed the related decommissioning liabilities. |
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(2) |
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In the year ended December 31, 2004, our subsidiary, SPN Resources, LLC, acquired additional
oil and gas properties through the acquisition of interests in 19 offshore Gulf of Mexico
leases. Under the terms of these transactions, we paid approximately $10.7 million (net of
approximately $5.0 million cash received), acquired the properties and assumed the related
decommissioning liabilities. |
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(3) |
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In the year ended December 31, 2001, we made five acquisitions for $108 million in initial
aggregate consideration, of which $2 million was paid with common stock. These acquisitions
have been accounted for as purchases, and the results of operations have been included from
the respective companys acquisition date. |
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(4) |
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In 2001, we changed depreciation methods from the straight-line method to the units of
production method on our liftboat fleet. The cumulative effect of this change in accounting
principle on prior years resulted in an increase in net income of $2.6 million, net of income
taxes of $1.7 million. |
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 provider of specialized oilfield services and equipment focused 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,
marine and other oilfield services segments. In recent years, we have expanded geographically so
that we now have a growing presence in select domestic land and international markets. 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 future commodity prices, drilling rig count, oil and gas
production levels, and customers capital spending allocated for drilling and production.
The primary factors driving our performance in 2005 were (1) increased customer spending levels on
finding and replacing oil and gas reserves due to high commodity prices; (2) increased customer
focus on replacing reserves through production-enhancement projects in existing wells; and (3) the
active hurricane season, which disrupted a strong Gulf of Mexico market, but created incremental
long-term demand for our products and services.
In 2005, activity across all segments increased throughout the year, particularly in the Gulf of
Mexico. However, the extraordinarily active hurricane season highlighted by damage caused by
Hurricanes Katrina and Rita disrupted most Gulf of Mexico-based well intervention service and
rental tool activity for almost three months following the storms.
By mid-November, pre-storm Gulf activity levels resumed for well intervention services and rental
tools and by year-end demand for most services and tools were exceeding those levels. The marine
segment participated in post-storm damage assessment and construction support projects throughout
the fourth quarter. By the end of the year, liftboat demand continued to grow due to the
post-hurricane construction and repair work, coupled with well intervention work that was deferred
prior to the storms. This led to unprecedented dayrates for liftboats as year-end dayrates were
50% higher than rates in August 2005, and 30% higher than dayrates we were generating during the
second and third quarters of 2001 when prior peak dayrates were established. Also, for the first
time in several years, we were able to achieve meaningful price increases for some of our well
intervention services. Financial performance for services has traditionally been driven by volume,
or utilization, while pricing improvement has been difficult to achieve. However, pent-up demand
and incremental work created by hurricane damage have allowed us to raise prices on some services
by as much as 20%.
The active hurricane season also caused significant damage to the industrys Gulf of Mexico
infrastructure. Our participation in the Gulf of Mexico repair efforts include project management;
marine and well control engineering; relief well planning, supervision and execution; well
intervention planning; offshore supervision and offshore site and activity management; well
abandonment; and specialty equipment and tools. In addition, we will provide our liftboats, well
intervention services and rental tools to many more projects that we are not managing.
Our oil and gas production remained largely shut-in following the hurricanes due to hurricane
damage. During the fourth quarter, we were repairing our properties and awaiting repairs to
pipelines owned by third parties. Average production during the second quarter of 2005, prior to
the active hurricane season, was approximately 7,200 barrels of oil equivalent (boe) per day.
However, in the third and fourth quarters, production averaged approximately 4,600 boe per day and
1,100 boe per day, respectively. All of our production is expected to be restored by the end of
the first quarter of 2006.
21
In our other geographic market areas, we benefited from increased levels of customer spending
driven by high commodity prices. International revenue was a record $99.3 million, primarily due
to continued expansion of our rental tools business in markets such as the North Sea, Venezuela,
the Middle East and West Africa and well intervention activity in Australia, Egypt and Venezuela.
Approximately 55% of our international revenue is derived from the rental tools segment. The
remainder is derived from well intervention services such as hydraulic workover, sidetrack drilling
and well control services.
Domestically, we aggressively expanded our rentals of drill pipe, ancillary tubulars, handling
tools, stabilizers, and drill collars to market areas in Arkansas, Louisiana, Texas, Oklahoma and
Wyoming. Toward the end of the year we expanded our well intervention services in these market
areas. Drilling rig counts and production-related spending are expected to grow domestically on
land, and we believe we can successfully expand our presence in these market areas. As a result,
demand should continue at high levels in the markets in which we compete due to the current high
level of commodity prices and our customers focus on rapidly replacing oil and gas reserves from
reservoirs that deliver the highest returns for the least amount of risk.
In the Gulf of Mexico, activity is expected to remain robust. In the deepwater Gulf, large energy
producers continue to fund exploration and drilling programs in an effort to locate and produce
large reservoirs of oil and gas. The shallow water Gulf is more mature, providing
production-enhancement opportunities for smaller operators.
The mature nature of the shallow water Gulf market should benefit our newly constructed derrick
barge which is expected to be available during the third quarter of 2006 and increase our
ability to acquire additional mature properties. We expect decommissioning activity to accelerate
as shallow water wells become uneconomical and platforms must be removed. Mature wells often
require significant intervention to enhance, extend and maintain production. The costs of this
intervention, coupled with the additional risks associated with hurricanes, may lead many energy
producers to re-assess the costs and benefits of owning these mature properties.
Well Intervention Segment
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, special
projects such as well control can directly increase the gross margin percentage.
Revenue and operating income were 17% and 20% higher, respectively, as compared to 2004 despite
significant hurricane-related downtime in the Gulf of Mexico. This downtime was more than offset
by strong Gulf of Mexico activity levels during the first half of the year, especially for services
such as coiled tubing, mechanical wireline and electric line services, and improved pricing for
many services toward the end of the year. In addition, year-over-year performance improved
significantly for well control and hydraulic workover services in non-Gulf of Mexico markets.
Rental Tools Segment
The rental tools segment is capital intensive with high operating margins as a result of relatively
low operating costs. The largest fixed cost is typically depreciation as there is little labor
associated with our rental tools business. Pricing generally does not fluctuate and financial
performance is a function of changes in volume rather than pricing.
Revenue increased 43% and operating income increased 68% over 2004. The biggest increases in
revenue and operating income were from the rentals of drill pipe, particularly rentals in
international markets, as well as rentals of on-site accommodations and handling tools. Rentals
outside the Gulf of Mexico represented more than 60% of this segments total revenue in 2005.
Marine Segment
The operating costs of our liftboats are relatively fixed and, therefore, gross margin percentages
vary significantly from quarter-to-quarter and year-to-year based on changes in dayrates and
utilization levels. As an indication of this
22
segments performance, our gross margin percentages
were 40% in the first quarter, 32% in the second quarter, 36% in the third quarter and 62% in the
fourth quarter.
Revenue increased 25% and operating income increased more than 320% over 2004. Liftboat dayrates
and utilization steadily increased during the first and second quarters of the year. Activity
levels were improving in August prior to Hurricanes Katrina and Rita. Following the storms,
dayrates increased to record levels and liftboat utilization averaged approximately 90% during the
fourth quarter as our liftboats were used to support our customers damage assessment and
construction projects.
We sold 17 of our smaller liftboats during the second quarter. These liftboats had lower gross
profit percentages than our fleet of larger liftboats.
Other Oilfield Services
More than half of this segments revenues are derived from our offshore platform and property
management business, a labor-intensive business with low margins. Environmental services, such as
dockside vessel and tank cleaning and non-hazardous oilfield waste treatment, comprise most of the
other revenue in this segment.
Revenues increased 9% over 2004, but our operating loss increased to $6.8 million from $2.6 million
in 2004. This segments operating loss would have decreased by approximately $4.9 million if we
did not incur non-recurring, non-cash charges related to the sale of our oil spill response assets
and the reduction in value of our non-hazardous oilfield waste treatment business as a result of
our intent to sell the business. The segments customer base operates in the Gulf of Mexico and
along the Gulf Coast. The 2005 hurricane season disrupted drilling activity during the last half
of the year, adversely impacting production and drilling activity, the primary drivers for our
offshore platform and property management business and our environmental businesses, respectively.
Also, several of our Gulf Coast facilities suffered hurricane-related damage, limiting our
environmental service capabilities during the third and fourth quarters.
Oil and Gas Segment
Through our subsidiary SPN Resources, LLC, we acquire, manage and decommission mature properties in
the shallow waters of the Gulf of Mexico. As of December 31, 2005, we had interests in 32 offshore
blocks containing 58 structures and approximately 140 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 fixed cost
nature 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 these types of properties are typically relatively high because of
the amount of well intervention service work required to enhance, maintain and extend production
for mature properties. The gross operating margin is also a function of oil and gas prices.
Revenues were 113% higher and operating income was 76% higher than 2004. Although we benefited
from higher commodity prices and more production as a result of properties we
acquired in 2004, approximately 744,000 boe of production was deferred as a result of extensive
damage caused by the active hurricane season. We did not suffer any permanent damage to wells, and
we expect our production to be fully-restored by the end of the first quarter of 2006.
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
23
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 the portrayal
of 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 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.
24
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 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 up to certain levels for losses related to workers
compensation, protection and indemnity, general liability, property damage, and group medical.
With the recent tightening in the insurance markets, we have elected 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, health care
costs 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 reinsurance 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 value (including an estimated profit) 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 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 out-of-pocket costs, the difference is reported as income (or loss) in the period in
which the work is performed. We review the adequacy of our decommissioning 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.
25
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 and
generally accepted accounting principles. 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.
Derivative Instruments and Hedging Activities. We enter into hedging transactions for our
oil production to reduce exposure to the fluctuations in oil prices. Our hedging transactions to
date have consisted of financially-settled crude oil swaps and zero-cost collars with a major
financial institution. We may in the future enter into these and other types of hedging
arrangements to reduce our exposure to fluctuations in the market prices of oil and natural gas.
Under the provisions of Statement of Financial Accounting Standards No. 133, Accounting for
Derivative Instruments and Hedging Activities, we are required to record our derivative
instruments at fair market value as either assets or liabilities in our consolidated balance sheet.
The fair market value is an estimate based on future commodity prices available at the time of the
calculation. The fair market value could differ from actual settlements if the other party to the
contract defaults on its obligations or there is a change in the expected differential between the
underlying price in the hedging agreement and actual prices received.
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
five business segments. Oil and gas eliminations represent products and services provided to the
oil and gas segment by the Companys four other segments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue |
|
Gross Margin |
|
|
2005 |
|
2004 |
|
Change |
|
2005 |
|
% |
|
2004 |
|
% |
|
Change |
|
|
|
|
|
Well Intervention |
|
$ |
248,576 |
|
|
$ |
211,820 |
|
|
$ |
36,756 |
|
|
$ |
106,242 |
|
|
|
43 |
% |
|
$ |
89,755 |
|
|
|
42 |
% |
|
$ |
16,487 |
|
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 |
|
Other Oilfield Services |
|
|
91,033 |
|
|
|
83,870 |
|
|
|
7,163 |
|
|
|
19,729 |
|
|
|
22 |
% |
|
|
16,077 |
|
|
|
19 |
% |
|
|
3,652 |
|
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.
26
Well Intervention Segment
Revenue for our well intervention segment was $248.6 million for the year ended December 31, 2005,
as compared to $211.8 million for 2004. This segments gross margin percentage increased slightly
to 43% in 2005 from 42% 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 and wireline 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 increased demand and the sale of our lower margin rental liftboats. The fleets
average dayrate increased 47% to approximately $9,223 in the year ended December 31, 2005 from
$6,295 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.
Other Oilfield Services Segment
Revenue from our other oilfield services segment for the year ended December 31, 2005 was $91.0
million, a 9% increase over the $83.9 million in revenue for 2004. The gross margin percentage
increased to 22% in the year ended December 31, 2005 from 19% in 2004. The revenue increase is
primarily due to increased demand for our field management and waste disposal services. The
increase in the segments gross margin percentage is due to the increased demand as well as cost
saving efforts in our waste disposal services. This segment incurred an operating loss of
approximately $6.8 million, which includes approximately $2.1 million of storm-related general
and administrative expenses primarily due to damage to its equipment and facilities from
Hurricanes Katrina and Rita and $4.9 million of losses as the result of our decision to sell-off
our oil spill response inventory and equipment and our non-hazardous waste disposal service
business.
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
27
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 non-hazardous oilfield waste subsidiary, Environmental
Treatment Team, L.L.C. (ETT) for approximately $18.7 million in cash. We reduced the net asset
value of ETT 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.
Comparison of the Results of Operations for the Years Ended December 31, 2004 and 2003
For the year ended December 31, 2004, our revenues were $564.3 million resulting in net income of
$35.9 million or $0.47 diluted earnings per share. For the year ended December 31, 2003,
revenues were $500.6 million and net income was $30.5 million which includes $2.8 million of
pre-tax other income due to the gain from insurance proceeds; diluted earnings per
share was $0.41 for the same period. We experienced higher revenues from our rental tools and
well intervention segments. We also benefited from oil and gas production following our initial
acquisition of properties in the Gulf of Mexico in December 2003.
The following table compares our operating results for the years ended December 31, 2004 and
2003. Gross margin is calculated by subtracting cost of services from revenue for each of our
five business segments. Oil and gas eliminations represent products and services provided to the
oil and gas segment by the Companys four other segments.
28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue |
|
Gross Margin |
|
|
2004 |
|
2003 |
|
Change |
|
2004 |
|
% |
|
2003 |
|
% |
|
Change |
|
|
|
|
|
Well Intervention |
|
$ |
211,820 |
|
|
$ |
187,271 |
|
|
$ |
24,549 |
|
|
$ |
89,755 |
|
|
|
42 |
% |
|
$ |
75,941 |
|
|
|
41 |
% |
|
$ |
13,814 |
|
Rental Tools |
|
|
170,064 |
|
|
|
141,362 |
|
|
|
28,702 |
|
|
|
112,711 |
|
|
|
66 |
% |
|
|
95,243 |
|
|
|
67 |
% |
|
|
17,468 |
|
Marine |
|
|
69,808 |
|
|
|
70,370 |
|
|
|
(562 |
) |
|
|
20,227 |
|
|
|
29 |
% |
|
|
20,056 |
|
|
|
29 |
% |
|
|
171 |
|
Other Oilfield Services |
|
|
83,870 |
|
|
|
100,881 |
|
|
|
(17,011 |
) |
|
|
16,077 |
|
|
|
19 |
% |
|
|
19,368 |
|
|
|
19 |
% |
|
|
(3,291 |
) |
Oil and Gas |
|
|
37,008 |
|
|
|
741 |
|
|
|
36,267 |
|
|
|
15,461 |
|
|
|
42 |
% |
|
|
410 |
|
|
|
55 |
% |
|
|
15,051 |
|
Less: Oil and Gas Elim |
|
|
(8,231 |
) |
|
|
|
|
|
|
(8,231 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
564,339 |
|
|
$ |
500,625 |
|
|
$ |
63,714 |
|
|
$ |
254,231 |
|
|
|
45 |
% |
|
$ |
211,018 |
|
|
|
42 |
% |
|
$ |
43,213 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following discussion analyzes our operating results on a segment basis.
Well Intervention Segment
Revenue for our well intervention segment was $211.8 million for the year ended December 31, 2004,
as compared to $187.3 million for the same period in 2003. This segments gross margin percentage
increased to 42% in the year ended December 31, 2004 from 41% in 2003. We experienced increased
demand for almost all of our services, and we also benefited by completing various decommissioning
projects on our oil and gas properties. These increases in demand and decommissioning projects
contributed to the improvement in the segments gross margin percentage.
Rental Tools Segment
Revenue for our rental tools segment for the year ended December 31, 2004 was $170.1 million, a
20% increase over 2003. The increase in this segments revenue was primarily due to an increased
demand for our expanded inventory of downhole rental tool equipment and our continued
international expansion, due primarily to the August 2003 acquisition of Premier Oilfield
Services. In addition, we benefited from increased bolting, torque and on-site machining work and
increased rentals of stabilizers and housing units. The gross margin percentage declined slightly
to 66% in the year ended December 31, 2004 from 67% in of 2003 due primarily to a change in the
mix of our rental revenue.
Marine Segment
Our marine segment revenue for the year ended December 31, 2004 slightly decreased 1% from 2003 to
$69.8 million. The gross margin percentage for the year ended December 31, 2004 remained unchanged
at 29%. The fleets average dayrate decreased slightly to $6,295 in the year ended December 31,
2004 from $6,306 in 2003, but average utilization increased to 72% for the year ended December 31,
2004 from 66% in 2003. Average fleet dayrates entering 2004 were significantly less than the same
period a year ago due to lower demand for liftboats. As liftboat utilization increased throughout
the year, we began to experience higher rates, particularly in the third and fourth quarters.
Other Oilfield Services Segment
Other oilfield services revenue for the year ended December 31, 2004 was $83.9 million, a 17%
decrease over the $100.9 million in revenue for 2003. The lower revenue is primarily attributable
to the sale of our construction and fabrication assets in August 2003, which had revenue of
approximately $19.0 million in 2003. The gross margin percentage remained unchanged at 19% in
2004 and 2003. The decrease in revenue resulted in a $2.6 million operating loss for this segment
in 2004.
Oil and Gas Segment
Oil and gas revenues were $37.0 million and the gross margin percentage was 42% for the year ended
December 31, 2004, compared to revenues of $0.7 million and gross margin percentage of 55% for the
year ended December 31, 2003. The increase in revenue is due to the fact that our oil and gas
segment began in December
29
2003 and has benefited from the South Pass 60 acquisition completed in
July 2004. The segment was negatively impacted by Hurricane Ivan which shut-in or curtailed
production from the South Pass 60 field beginning in mid-September 2004 through late December
2004.
Depreciation, Depletion, Amortization and Accretion
Depreciation, depletion, amortization and accretion increased to $67.3 million in the year ended
December 31, 2004 from $48.9 million in 2003. The increase is primarily a result of depletion and
accretion related to our oil and gas properties. The increase is also the result of our
acquisition of Premier Oilfield Services in August 2003 and capital expenditures during 2003 and
2004.
General and Administrative
General and administrative expenses increased to $110.6 million for the year ended December 31,
2004 from $94.8 million in 2003. The increase is primarily the result of our acquisitions,
internal growth and international expansion.
Liquidity and Capital Resources
In the year ended December 31, 2005, we generated net cash from operating activities of $158.4
million as compared to $91.3 million in 2004. Our primary liquidity needs are for working capital,
capital expenditures, debt service and acquisitions. Our primary sources of liquidity are cash
flows from operations and borrowings under our revolving credit facility. We had cash and cash
equivalents of $54.5 million at December 31, 2005 compared to $15.3 million at December
31, 2004.
We made $125.2 million of capital expenditures during the year ended December 31, 2005, of which
approximately $68.5 million was used to expand and maintain our rental tool equipment inventory.
We also made $19.7 million of capital expenditures in our oil and gas segment and $32.8 million of
capital expenditures, inclusive of $6.7 million in progress payments made on the crane as noted
below and $5.6 million for the purchase of a 200-foot class liftboat which we were previously
operating, to expand and maintain the asset base of our well intervention, marine and other
oilfield services segments. In addition, we made $4.2 million of capital expenditures on
construction and improvements to our facilities.
In March 2005, we contracted to construct an 880-ton derrick barge to support our decommissioning
operations on the Outer Continental Shelf. The contracts are for the construction of a 350-foot
barge and crane for a price of approximately $23 million. This amount does not include any future
change orders, barge outfitting or mobilization costs. Progress payments were made on the crane in
accordance with the terms set forth in the contract. Letters of credit are due on the barge based
on contract milestones. The contract price for the barge will be payable upon its delivery and
acceptance. We expect the barge to be available in the Gulf of Mexico late in the third quarter of
2006. We intend to utilize it to remove platforms and structures owned by our subsidiary, SPN
Resources, LLC, and compete in the Gulf of Mexico construction market for both installation and
removal projects. At December 31, 2005, the total amount of progress payments made on the crane
was approximately $6.7 million. We also placed a deposit of approximately $0.6 million on an
anchor handling tug for the barge. The remaining balance of approximately $5.3 million is expected
to be paid in the first quarter of 2006.
We also paid additional consideration for prior acquisitions of $5.3 million in 2005, all of which
were capitalized and accrued during 2004.
We have a bank credit facility consisting of a revolving credit facility of $150 million, with an
option to increase it to $250 million. Any balance outstanding on the revolving credit facility is
due on October 31, 2008. The credit facility bears interest at a LIBOR rate plus margins that
depend on the Companys leverage ratio. As of February 17, 2006, there was no balance outstanding
on this credit facility. 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 capital expenditures, its 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 which would require supplemental bonding.
30
We have $17.4 million outstanding at December 31, 2005 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.
We also have outstanding $200 million of 8 7/8% senior notes due 2011. The indenture governing the
senior notes requires semi-annual interest payments on every May 15th and November
15th through the maturity date of May 15, 2011. We may redeem the senior notes during
the 12-month period commencing May 15, 2006 at 104.438% of the principal amount redeemed. The
indenture governing the senior notes contains certain covenants that, among other things, prevent
us from incurring additional debt, paying dividends or making other distributions, unless our ratio
of cash flow to interest expense is at least 2.25 to 1, except that we may incur debt in addition
to the senior notes in an amount equal to 30% of our net tangible assets, which was approximately
$208 million at December 31, 2005. The indenture also contains covenants that restrict our ability
to create certain liens, sell assets or enter into certain mergers or acquisitions.
The following table summarizes our contractual cash obligations and commercial commitments at
December 31, 2005 (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 $31.5 million, when decommissioning operations
are performed. We do not have any other material obligations or commitments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Description |
|
2006 |
|
2007 |
|
2008 |
|
2009 |
|
2010 |
|
Thereafter |
|
Long-term debt, including
estimated interest payments |
|
$ |
19,670 |
|
|
$ |
19,617 |
|
|
$ |
19,565 |
|
|
$ |
19,513 |
|
|
$ |
19,461 |
|
|
$ |
229,549 |
|
Decommissioning liabilities |
|
|
14,268 |
|
|
|
26,408 |
|
|
|
7,294 |
|
|
|
3,831 |
|
|
|
13,609 |
|
|
|
56,499 |
|
Operating leases |
|
|
6,360 |
|
|
|
4,837 |
|
|
|
2,723 |
|
|
|
1,667 |
|
|
|
1,137 |
|
|
|
14,181 |
|
Derrick barge and tug
construction |
|
|
21,263 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
61,561 |
|
|
$ |
50,862 |
|
|
$ |
29,582 |
|
|
$ |
25,011 |
|
|
$ |
34,207 |
|
|
$ |
300,229 |
|
|
|
|
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, 2005, 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 have identified capital expenditure projects that will require approximately $214 million in
2006, exclusive of any acquisitions for, among other things, geographic expansion, the construction
of our derrick barge and anchor handling tug, the refurbishment of a 200-foot class liftboat and
reserve additions in our oil and gas segment. We 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
31
require additional equity or
debt financing in excess of our current working capital and amounts available under our revolving
credit facility.
Hedging Activities
We enter into hedging transactions with major financial institutions to secure a commodity price
for a portion of our future production and to reduce our exposure to fluctuations in the price of
oil. We do not enter into hedging transactions for trading purposes. Crude oil hedges are settled
based on the average of the reported settlement prices for West Texas Intermediate crude on the New
York Mercantile Exchange (NYMEX) for each month. We had no natural gas hedges as of December 31,
2005 and 2004. We use financially-settled crude oil swaps and zero-cost collars that provide floor
and ceiling prices with varying upside price participation. Our swaps and zero-cost collars are
designated and accounted for as cash flow hedges.
With a financially-settled swap, the counterparty is required to make a payment to us if the
settlement price for any settlement period is below the hedged price for the transaction, and we
are required to make a payment to the counterparty if the settlement price for any settlement
period is above the hedged price for the transaction. With a zero-cost collar, the counterparty is
required to make a payment to us if the settlement price for any settlement period is below the
floor price of the collar, and we are required to make a payment to the counterparty if the
settlement price for any settlement period is above the cap price for the collar. We recognize the
fair value of all derivative instruments as assets or liabilities on the balance sheet. Changes in
the fair value of cash flow hedges are recognized, to the extent the hedge is effective, in other
comprehensive income until the hedged item is recognized in oil and gas revenues. For the year
ended December 31, 2005, hedging settlement payments reduced oil revenues by approximately $10.2
million dollars and gains or losses due to hedge ineffectiveness were not material.
We had the following hedging contracts as of December 31, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Positions |
|
|
|
Instrument |
|
|
Strike |
|
|
Volume (Bbls) |
|
|
|
|
Remaining Contract Term |
|
Type |
|
|
Price (Bbl) |
|
|
Daily |
|
|
Total (Bbls) |
|
01/06 - 8/06 |
|
Swap |
|
$ |
39.45 |
|
|
|
1,000 - 1,013 |
|
|
|
274,388 |
|
01/06 - 8/06 |
|
Collar |
|
$ |
35.00/$45.60 |
|
|
|
1,000 - 1,013 |
|
|
|
274,388 |
|
Recently Issued Accounting Pronouncements
In December 2004, the Financial Accounting Standards Board revised its Statement of Financial
Accounting Standards No. 123 (FAS No. 123R), Accounting for Stock Based Compensation. Under FAS
No. 123R, companies will be required to recognize as expense the estimated fair value of all
share-based payments to employees, including the fair value of employee stock options. This
expense will be recognized over the period during which the employee is required to provide service
in exchange for the award. Pro forma disclosure of the estimated expense impact of such awards is
no longer an alternative to expense recognition in the financial statements. FAS No. 123R is
effective for public companies in the first annual period beginning after June 15, 2005, and
accordingly, we will adopt the provisions of FAS No. 123R effective January 1, 2006. We anticipate
using the modified prospective application transition method, which does not include restatement of
prior periods. We expect to record approximately $89,000 of compensation expense in 2006 due to
the adoption of FAS No. 123R for share-based awards granted prior to January 1, 2006. We expect
the effect of the adoption on future share-based awards to be consistent with the disclosure of pro
forma net income and earnings per share as displayed in note 1 of our consolidated financial
statements included in Item 8 of this Form 10-K.
In May 2005, the Financial Accounting Standards Board issued Statement of Financial Accounting
Standards No. 154 (FAS No. 154), Accounting Changes and Error Corrections. This Statement
replaces APB Opinion No. 20,
Accounting Changes and FASB Statement No. 3, Reporting Accounting Changes in Interim Financial
Statements. FAS No. 154 provides guidance on the accounting for and reporting of accounting
changes and error corrections. It establishes, unless impracticable, retrospective application as
the required method for reporting all changes in accounting principle in the absence of explicit
transition requirements of new pronouncements. FAS No.
32
154 is effective for accounting changes and
error corrections made in fiscal years beginning after December 15, 2005.
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 most of our
international operations 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 foreign subsidiaries 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, 2005, none of our long-term debt outstanding had variable interest rates, and we
had no interest rate risks at that time.
Commodity Price Risk
Our revenue, 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
and natural gas production. As of December 31, 2005, we had the following contracts in place:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Positions |
|
|
|
Instrument |
|
|
Strike |
|
|
Volume (Bbls) |
|
|
|
|
Remaining Contract Term |
|
Type |
|
|
Price (Bbl) |
|
|
Daily |
|
|
Total (Bbls) |
|
01/06 - 8/06 |
|
Swap |
|
$ |
39.45 |
|
|
|
1,000 - 1,013 |
|
|
|
274,388 |
|
01/06 - 8/06 |
|
Collar |
|
$ |
35.00/$45.60 |
|
|
|
1,000 - 1,013 |
|
|
|
274,388 |
|
Our hedged volume as of December 31, 2005 was approximately 50% of our estimated production from
proved reserves for the balance of the terms of the contracts. Had these contracts been terminated
at December 31, 2005, the estimated loss would have been $6.9 million, net of taxes.
We used a sensitivity analysis technique to evaluate the hypothetical effect that changes in the
market value of crude oil would have on the fair value of its existing derivative instruments.
Based on the derivative instruments
outstanding at December 31, 2005, a 10% increase in the underlying commodity price, increased the
net estimated loss associated with the commodity derivative instrument by $1.9 million.
33
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, and for performing an assessment of the effectiveness of internal control over
our financial reporting as of December 31, 2005. Our 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. Our system of internal control over financial reporting includes
those 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.
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, 2005 based upon criteria in Internal Control Integrated Framework, issued by the
Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment under
the criteria in Internal Control Integrated Framework, our management determined that our
internal control over financial reporting was effective as of December 31, 2005.
Our managements assessment of the effectiveness of our internal control over financial reporting
as of December 31, 2005 has been audited by KPMG LLP, an independent registered public accounting
firm, as stated in their report which appears herein.
|
|
|
|
|
|
/s/ Terence E. Hall |
|
/s/ Robert S. Taylor |
|
|
Terence E. Hall
Chairman of the Board and
Chief Executive Officer
|
|
Robert S. Taylor
Chief Financial Officer,
Executive Vice President and Treasurer |
|
34
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, 2005 and 2004, 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, 2005. 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, 2005, 2004 and 2003. 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, 2005 and 2004, and the results of their operations and their cash flows for each of
the years in the three-year period ended December 31, 2005, 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 therin.
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, 2005, based on criteria established in Internal
ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO), and our report dated March 8, 2006 expressed an unqualified opinion on
managements assessment of, and the effective operation of, internal control over financial
reporting.
KPMG LLP
New Orleans, Louisiana
March 8, 2006
35
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, 2005, 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, 2005, 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, 2005, based on criteria established in Internal
ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO).
36
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, 2005 and 2004, 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, 2005. 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, 2005, 2004 and 2003. Our report dated March
8, 2006 expressed an unqualified opinion on those consolidated financial statements and schedule.
KPMG, LLP
New Orleans, Louisiana
March 8, 2006
37
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
December 31, 2005 and 2004
(in thousands, except share data)
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
2004 |
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
54,457 |
|
|
$ |
15,281 |
|
Accounts receivable, net of allowance for doubtful accounts of $11,569 and
$8,364 at December 31, 2005 and 2004, respectively |
|
|
196,365 |
|
|
|
156,235 |
|
Income taxes receivable |
|
|
|
|
|
|
2,694 |
|
Current portion of notes receivable |
|
|
2,364 |
|
|
|
9,611 |
|
Prepaid insurance and other |
|
|
51,116 |
|
|
|
28,203 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
304,302 |
|
|
|
212,024 |
|
|
|
|
|
|
|
|
Property, plant and equipment, net |
|
|
440,328 |
|
|
|
431,334 |
|
Oil and gas assets, net, under the successful efforts method of accounting |
|
|
94,634 |
|
|
|
83,817 |
|
Goodwill, net |
|
|
220,064 |
|
|
|
226,593 |
|
Notes receivable |
|
|
29,483 |
|
|
|
29,131 |
|
Investments in affiliates |
|
|
|
|
|
|
13,552 |
|
Other assets, net |
|
|
8,439 |
|
|
|
7,462 |
|
|
|
|
|
|
|
|
Total assets |
|
$ |
1,097,250 |
|
|
$ |
1,003,913 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
42,035 |
|
|
$ |
36,496 |
|
Accrued expenses |
|
|
69,926 |
|
|
|
56,796 |
|
Income taxes payable |
|
|
11,353 |
|
|
|
|
|
Fair value of commodity derivative instruments |
|
|
10,792 |
|
|
|
2,018 |
|
Current portion of decommissioning liabilities |
|
|
14,268 |
|
|
|
23,588 |
|
Current maturities of long-term debt |
|
|
810 |
|
|
|
11,810 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
149,184 |
|
|
|
130,708 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred income taxes |
|
|
97,987 |
|
|
|
103,372 |
|
Decommissioning liabilities |
|
|
107,641 |
|
|
|
90,430 |
|
Long-term debt |
|
|
216,596 |
|
|
|
244,906 |
|
Other long-term liabilities |
|
|
1,468 |
|
|
|
618 |
|
|
|
|
|
|
|
|
|
|
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 79,499,927 and 76,766,303 shares at December 31, 2005
and 2004, respectively |
|
|
79 |
|
|
|
77 |
|
Additional paid in capital |
|
|
428,507 |
|
|
|
398,073 |
|
Accumulated other comprehensive income (loss) |
|
|
(4,916 |
) |
|
|
2,884 |
|
Retained earnings |
|
|
100,704 |
|
|
|
32,845 |
|
|
|
|
|
|
|
|
Total stockholders equity |
|
|
524,374 |
|
|
|
433,879 |
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
1,097,250 |
|
|
$ |
1,003,913 |
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
38
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Operations
Years Ended December 31, 2005, 2004 and 2003
(in thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
Oilfield service and rental revenues |
|
$ |
656,423 |
|
|
$ |
527,331 |
|
|
$ |
499,884 |
|
Oil and gas revenues |
|
|
78,911 |
|
|
|
37,008 |
|
|
|
741 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
735,334 |
|
|
|
564,339 |
|
|
|
500,625 |
|
|
|
|
|
|
|
|
|
|
|
Cost of oilfield services and rentals |
|
|
330,200 |
|
|
|
288,561 |
|
|
|
289,276 |
|
Cost of oil and gas sales |
|
|
45,804 |
|
|
|
21,547 |
|
|
|
331 |
|
|
|
|
|
|
|
|
|
|
|
Total cost of services, rentals and sales |
|
|
376,004 |
|
|
|
310,108 |
|
|
|
289,607 |
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion, amortization and accretion |
|
|
89,288 |
|
|
|
67,337 |
|
|
|
48,853 |
|
General and administrative expenses |
|
|
140,989 |
|
|
|
110,605 |
|
|
|
94,822 |
|
Reduction in value of assets |
|
|
6,994 |
|
|
|
|
|
|
|
|
|
Gain on sale of liftboats |
|
|
3,544 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations |
|
|
125,603 |
|
|
|
76,289 |
|
|
|
67,343 |
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense, net of amounts capitalized |
|
|
(21,862 |
) |
|
|
(22,476 |
) |
|
|
(22,477 |
) |
Interest income |
|
|
2,201 |
|
|
|
1,766 |
|
|
|
209 |
|
Other income |
|
|
|
|
|
|
|
|
|
|
2,762 |
|
Equity in earnings of affiliates |
|
|
1,339 |
|
|
|
1,329 |
|
|
|
985 |
|
Reduction in value of investment in affiliate |
|
|
(1,250 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
106,031 |
|
|
|
56,908 |
|
|
|
48,822 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes |
|
|
38,172 |
|
|
|
21,056 |
|
|
|
18,308 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
67,859 |
|
|
$ |
35,852 |
|
|
$ |
30,514 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share |
|
$ |
0.87 |
|
|
$ |
0.48 |
|
|
$ |
0.41 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share |
|
$ |
0.85 |
|
|
$ |
0.47 |
|
|
$ |
0.41 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares used in computing
earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
78,321 |
|
|
|
74,896 |
|
|
|
73,970 |
|
Incremental common shares from stock options |
|
|
1,414 |
|
|
|
1,004 |
|
|
|
678 |
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
|
79,735 |
|
|
|
75,900 |
|
|
|
74,648 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
39
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Changes in Stockholders Equity
Years Ended December 31, 2005, 2004 and 2003
(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) |
|
deficit) |
|
Total |
|
|
|
Balances, December
31, 2002 |
|
|
|
|
|
$ |
|
|
|
|
73,819,341 |
|
|
$ |
74 |
|
|
$ |
368,746 |
|
|
$ |
43 |
|
|
$ |
(33,521 |
) |
|
$ |
335,342 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive
income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30,514 |
|
|
|
30,514 |
|
Other comprehensive
income -
Foreign currency
translation
adjustment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
221 |
|
|
|
|
|
|
|
221 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive
income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
221 |
|
|
|
30,514 |
|
|
|
30,735 |
|
Exercise of stock
options and
directors stock
compensation |
|
|
|
|
|
|
|
|
|
|
279,740 |
|
|
|
|
|
|
|
1,710 |
|
|
|
|
|
|
|
|
|
|
|
1,710 |
|
Tax benefit from
stock options |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
342 |
|
|
|
|
|
|
|
|
|
|
|
342 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
outstanding
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 |
|
Conversion of
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
outstanding
hedging
positions, net
of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,662 |
) |
|
|
|
|
|
|
(2,662 |
) |
Foreign currency
translation
adjustment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,138 |
) |
|
|
|
|
|
|
(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.
40
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Years Ended December 31, 2005, 2004 and 2003
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
67,859 |
|
|
$ |
35,852 |
|
|
$ |
30,514 |
|
Adjustments to reconcile net income to net cash
provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion, amortization and accretion |
|
|
89,288 |
|
|
|
67,337 |
|
|
|
48,853 |
|
Deferred income taxes |
|
|
442 |
|
|
|
15,234 |
|
|
|
15,183 |
|
Reduction in value of assets |
|
|
6,994 |
|
|
|
|
|
|
|
|
|
Equity in income of affiliates |
|
|
(1,339 |
) |
|
|
(1,329 |
) |
|
|
(985 |
) |
Reduction in value of investment in affiliate |
|
|
1,250 |
|
|
|
|
|
|
|
|
|
Gain on sale of liftboats |
|
|
(3,544 |
) |
|
|
|
|
|
|
|
|
Other income |
|
|
|
|
|
|
|
|
|
|
(2,762 |
) |
Amortization of debt acquisition costs |
|
|
1,127 |
|
|
|
887 |
|
|
|
1,026 |
|
Changes in operating assets and liabilities, net of
acquisitions: |
|
|
|
|
|
|
|
|
|
|
|
|
Receivables |
|
|
(32,095 |
) |
|
|
(35,279 |
) |
|
|
104 |
|
Other, net |
|
|
(11,263 |
) |
|
|
(9,346 |
) |
|
|
1,773 |
|
Accounts payable |
|
|
5,696 |
|
|
|
16,142 |
|
|
|
(1,932 |
) |
Accrued expenses |
|
|
16,599 |
|
|
|
13,866 |
|
|
|
2,561 |
|
Decommissioning liabilities |
|
|
(8,772 |
) |
|
|
(9,157 |
) |
|
|
|
|
Income taxes |
|
|
26,137 |
|
|
|
(2,876 |
) |
|
|
5,905 |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
158,379 |
|
|
|
91,331 |
|
|
|
100,240 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Payments for capital expenditures |
|
|
(125,166 |
) |
|
|
(74,125 |
) |
|
|
(50,175 |
) |
Acquisitions of businesses, net of cash acquired |
|
|
(6,435 |
) |
|
|
(24,361 |
) |
|
|
(14,298 |
) |
Acquisitions of oil and gas properties, net of cash acquired |
|
|
3,686 |
|
|
|
(10,676 |
) |
|
|
|
|
Cash proceeds from sale of liftboats |
|
|
19,588 |
|
|
|
|
|
|
|
|
|
Cash proceeds from sale of affiliate |
|
|
12,489 |
|
|
|
|
|
|
|
|
|
Cash proceeds from insurance settlement |
|
|
|
|
|
|
|
|
|
|
8,000 |
|
Other |
|
|
(1,097 |
) |
|
|
|
|
|
|
313 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(96,935 |
) |
|
|
(109,162 |
) |
|
|
(56,160 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net payments on revolving credit facility |
|
|
|
|
|
|
|
|
|
|
(9,250 |
) |
Principal payments on long-term debt |
|
|
(39,310 |
) |
|
|
(13,713 |
) |
|
|
(43,089 |
) |
Proceeds from long-term debt |
|
|
|
|
|
|
|
|
|
|
23,000 |
|
Payment of debt acquisition costs |
|
|
(439 |
) |
|
|
(60 |
) |
|
|
(479 |
) |
Proceeds from exercise of stock options |
|
|
18,161 |
|
|
|
10,271 |
|
|
|
2,052 |
|
Proceeds from issuance of stock |
|
|
|
|
|
|
130,265 |
|
|
|
|
|
Purchase and retirement of stock |
|
|
|
|
|
|
(113,438 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities |
|
|
(21,588 |
) |
|
|
13,325 |
|
|
|
(27,766 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of exchange rate changes in cash |
|
|
(680 |
) |
|
|
(7 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents |
|
|
39,176 |
|
|
|
(4,513 |
) |
|
|
16,314 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at beginning of year |
|
|
15,281 |
|
|
|
19,794 |
|
|
|
3,480 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of year |
|
$ |
54,457 |
|
|
$ |
15,281 |
|
|
$ |
19,794 |
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
41
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005, 2004 and 2003
(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 2005 presentation. |
|
|
(b) |
|
Business |
|
|
|
|
The Company is a leading provider of specialized oilfield services and equipment focusing
on serving the production-related needs of oil and gas companies in the Gulf of Mexico and
the drilling-related needs of oil and gas companies throughout the world. 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. |
|
|
|
|
In December 2003, the Company began acquiring oil and gas properties in order to provide
additional opportunities for its well intervention and platform management operations in
the Gulf of Mexico. The Company intends to continue to acquire mature properties from its
customers with modest amounts of estimated remaining productive life, to provide all of
its services to the properties to produce any remaining proven oil and gas reserves and to
decommission and abandon 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 continually 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 oil and gas
industry in the Gulf of Mexico. Oil and gas companies make capital expenditures on
exploration, drilling and production operations offshore. The level of these expenditures
has been characterized by significant volatility. |
|
|
|
|
The Company derives a significant amount of revenue from a small number of major and
independent oil and gas companies. In 2005, Shell accounted for approximately 10% of
total revenue, primarily related to our oil and gas and rental segments. No customer
accounted for more than 10% of the Companys total revenue in 2004. In 2003, one customer
accounted for approximately 11% of its total revenue, primarily in the well intervention
and other oilfield services segments. The Companys inability to continue to perform
services for a number of large existing customers, if not offset by sales to new or |
42
|
|
|
existing customers, could have a material adverse effect on the Companys business and
financial condition. |
|
|
(e) |
|
Cash Equivalents |
|
|
|
|
The Company considers all short-term deposits with a maturity of ninety 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 bad debts and various other adjustments. 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 allowances based on historical write-off experience and specific identification. |
|
|
(g) |
|
Prepaid Insurance and Other |
|
|
|
|
Prepaid insurance and other includes approximately $23.9 million and $11.1 million in
insurance receivables at December 31, 2005 and 2004, respectively. The December 31, 2005
balance is primarily due to the impact of Hurricanes Katrina and Rita on our oil and gas
properties, as well as our buildings and equipment. The December 31, 2004 balance is
primarily related to the impact of Hurricane Ivan on our oil and gas properties. 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. With the exception of the Companys
liftboats 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 |
|
|
|
|
Marine vessels and oil and gas producing assets are depreciated or depleted based on
utilization or units-of-production, because depreciation and depletion occur primarily
through use rather than through the passage of time. Units of production depreciation on
marine vessels is subject to a minimum amount of depreciation each year. |
|
|
|
|
The Company capitalizes interest on borrowings used to finance 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 2005
and 2003, the Company capitalized approximately $456,000 and $87,000, 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, |
43
|
|
|
except for liftboats which are grouped together by similar leg-lengths. Assets to be
disposed of are reported at the lower of the carrying amount or fair value less costs to
sell. |
|
|
|
|
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. |
|
|
|
|
The Company adopted Financial Accounting Standards Board Staff Position FAS 19-1,
Accounting for Suspended Well Costs (FSP 19-1) effective July 1, 2005. FSP 19-1 amended
Statement of Financial Accounting Standards No. 19 Financial Accounting and Reporting by
Oil and Gas Producing Companies (Statement 19), to permit the continued capitalization of
exploratory well costs beyond one year if (a) the well found a sufficient quantity of
reserves to justify its completion as a producing well and (b) the entity is making
sufficient progress assessing the reserves and the economic and operating viability of the
project. The Company has not, and does not currently drill in the areas that require
major capital expenditures before production can begin. The Company evaluated all
existing capitalized well costs under the provisions of FSP-19-1 and determined there was
no impact to the Companys consolidated financial statements. |
|
|
|
|
Oil and gas properties are assessed for impairment in value on a field-by-field basis
whenever 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, and the second step of the impairment
test is not required. No impairment loss was recognized in the years ended December 31,
2005, 2004 or 2003 under this method. However, the Company reduced the value of goodwill
by approximately $3.8 million to approximate the sales price of its subsidiary,
Environmental Treatment Team, L.L.C., (ETT), which was sold in the first quarter of 2006
(see note 3). Goodwill also decreased by approximately $2.7 million in 2005 as the result
of changes in foreign currency exchange rates. Accumulated amortization of goodwill is
$9.2 million at December 31, 2005 and 2004. |
|
|
(j) |
|
Notes Receivable |
|
|
|
|
Notes receivable consist primarily of commitments from the sellers of oil and gas
properties towards the abandonment of the acquired properties. Pursuant to the agreement
between the Company and a seller, |
44
|
|
|
the Company will invoice the seller agreed upon amounts during the course of
decommissioning (abandonment and structure removal). These receivables are recorded at
present value, and the related discounts are amortized to interest income, based on the
expected timing of the decommissionings. |
|
|
(k) |
|
Other Assets |
|
|
|
|
Other assets consist primarily of debt acquisition costs and deferred compensation plan
assets. Debt acquisition costs are being amortized over the term of the related debt,
which is from three to twenty-five years. The amortization of debt acquisition costs,
which is classified as interest expense, was approximately $1,127,000, $887,000 and
$1,026,000 for the years ended December 31, 2005, 2004 and 2003, respectively.
Accumulated amortization of other assets is approximately $6,062,000 and $4,604,000 at
December 31, 2005 and 2004, respectively. |
|
|
(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 out-of-pocket 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. |
|
|
|
|
SPN Resources purchased its first oil and gas properties and assumed the related
decommissioning liabilities in December 2003, thus comparable data for the year ended
December 31, 2003 is not material. The following table summarizes the activity for the
Companys decommissioning liability for the twelve months ended December 31, 2005 and 2004
(amounts in thousands): |
45
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
Decommissioning liabilities, at beginning of period |
|
$ |
114,018 |
|
|
$ |
38,853 |
|
Liabilities acquired and incurred |
|
|
11,494 |
|
|
|
83,021 |
|
Liabilities settled |
|
|
(8,772 |
) |
|
|
(9,157 |
) |
Accretion |
|
|
4,476 |
|
|
|
2,836 |
|
Revision in estimated liabilities |
|
|
693 |
|
|
|
(1,535 |
) |
|
|
|
|
|
|
|
Total |
|
|
121,909 |
|
|
|
114,018 |
|
Current portion of decommissioning liabilities |
|
|
14,268 |
|
|
|
23,588 |
|
|
|
|
|
|
|
|
Decommissioning liabilities, at end of period |
|
$ |
107,641 |
|
|
$ |
90,430 |
|
|
|
|
|
|
|
|
|
(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 produced and sold from those wells. |
|
|
(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, accounts receivable and
current maturities of long-term debt approximates their carrying amounts. The fair value
of the Companys long-term debt is approximately $227 million at December 31, 2005. |
|
|
(q) |
|
Foreign Currency Translation |
|
|
|
|
Assets and liabilities of the Companys foreign subsidiaries are translated at current
exchange rates, while income and expenses 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. |
46
|
(r) |
|
Stock Based Compensation |
|
|
|
|
The Company accounts for its stock based compensation under the principles prescribed by
the Accounting Principles Boards Opinion No. 25 (Opinion No. 25), Accounting for Stock
Issued to Employees However, Statement of Financial Accounting Standards No. 123 (FAS No.
123), Accounting for Stock-Based Compensation permits the continued use of the
intrinsic-value based
method prescribed by Opinion No. 25 but requires additional disclosures, including pro
forma calculations of earnings and net earnings per share as if the fair value method of
accounting prescribed by FAS No. 123 had been applied. No stock based compensation costs
from stock options are reflected in net income, as all options granted under those plans
had an exercise price equal to the market value of the underlying common stock on the date
of grant. Stock compensation costs from the grant of restricted stock units and
restricted stock are expensed as incurred (see note 11). The pro forma data presented
below is not representative of the effects on reported amounts for future years (amounts
are in thousands, except per share amounts). |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
Net income, as reported |
|
$ |
67,859 |
|
|
$ |
35,852 |
|
|
$ |
30,514 |
|
Stock-based employee compensation
expense, net of tax |
|
|
(4,421 |
) |
|
|
(6,999 |
) |
|
|
(2,671 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma net income |
|
$ |
63,438 |
|
|
$ |
28,853 |
|
|
$ |
27,843 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
Earnings, as reported |
|
$ |
0.87 |
|
|
$ |
0.48 |
|
|
$ |
0.41 |
|
Stock-based employee compensation
expense, net of tax |
|
|
(0.06 |
) |
|
|
(0.09 |
) |
|
|
(0.04 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma earnings per share |
|
$ |
0.81 |
|
|
$ |
0.39 |
|
|
$ |
0.37 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
Earnings, as reported |
|
$ |
0.85 |
|
|
$ |
0.47 |
|
|
$ |
0.41 |
|
Stock-based employee compensation
expense, net of tax |
|
|
(0.06 |
) |
|
|
(0.09 |
) |
|
|
(0.04 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma earnings per share |
|
$ |
0.79 |
|
|
$ |
0.38 |
|
|
$ |
0.37 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Black-Scholes option pricing model assumptions: |
|
|
|
|
|
|
|
|
|
|
|
|
Risk free interest rate |
|
|
3.85 |
% |
|
|
4.28 |
% |
|
|
2.65 |
% |
Expected life (years) |
|
|
6 |
|
|
|
5 |
|
|
|
3 |
|
Volatility |
|
|
38.91 |
% |
|
|
65.22 |
% |
|
|
58.61 |
% |
Dividend yield |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In December 2004, the Financial Accounting Standards Board revised its Statement of
Financial Accounting Standards No. 123 (FAS No. 123R), Accounting for Stock Based
Compensation. Under FAS No. 123R, companies will be required to recognize as expense the
estimated fair value of all share-based payments to employees, including the fair value of
employee stock options. This expense will be recognized over the period during which the
employee is required to provide service in exchange for the award. Pro forma disclosure
of the estimated expense impact of such awards is no longer an alternative to expense
recognition in the financial statements. FAS No. 123R is effective for public companies
in the first annual period beginning after June 15, 2005, and accordingly, the Company
will adopt the provisions of FAS No. 123R effective January 1, 2006. The Company
anticipates using the modified prospective application transition method, which does not
include restatement of prior periods. The Company expects to record approximately $89,000
of compensation expense in 2006 due to the adoption of FAS No. 123R for share-based awards
granted prior to January 1, 2006. The Company expects the |
47
|
|
|
effect of the adoption on future awards to be consistent with the disclosure of pro forma
net income and earnings per share as displayed above. |
|
|
|
|
Long-Term Incentive Plan |
|
|
|
|
In May 2005, the Companys stockholders approved the 2005 Stock Incentive Plan (2005
Incentive Plan) to provide long-term incentives to its officers, key employees,
consultants and advisers (Eligible Participants). Under the 2005 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 of common stock.
The Compensation Committee of the Board of Directors establishes the term and the exercise
price of any stock options granted under the 2005 Incentive Plan, provided the exercise
price may not be less than the fair market value of the common stock on the date of grant.
On June 24, 2005, the Compensation Committee awarded approximately 864,000 non-qualified
stock options to Eligible Participants under the 2005 Incentive Plan. This grant was
fully-vested by December 31, 2005. |
|
|
|
|
On June 24, 2005, the Compensation Committee also awarded approximately 32,000 performance
share units (Units). The performance period for the Units runs from January 1, 2005
through December 31, 2007. 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. Participants can earn from $0 to $200
per Unit, as determined by the Companys achievement of the performance measures. The
Units provide for settlement in cash or up to 50% in equivalent value in Company common
stock, if the participant has met specified continued service requirements. The Companys
compensation expense related to the grant of the Units was approximately $1.1 million,
which is reflected in general and administrative expenses, for the year ended December 31,
2005. |
|
|
|
|
Subsequent event |
|
|
|
|
On February 23, 2006, the Compensation Committee granted long-term incentive awards to
each of the Companys named executive officers and other key employees of the Company
under its stockholder approved 2005 Stock Incentive Plan. These awards consisted of
approximately 213,000 non-qualified stock options, 104,000 shares of restricted stock and
34,000 performance share units (Units). |
|
|
|
|
The non-qualified options will be exercisable in equal installments on the anniversary of
the date of the grant for three consecutive years, and will expire on the tenth
anniversary of the date grant. 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. The shares of restricted stock will be exercisable in equal installments on the
anniversary date of the grant for three consecutive years. The performance period for the
Units runs from January 1, 2006 through December 31, 2008. 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.
Participants can earn from $0 to $200 per Unit, as determined by the Companys achievement
of the performance measures. The Units provide for settlement in cash or up to 50% in
equivalent value in Company common stock, if the participant has met specified continued
service requirements. |
|
|
(s) |
|
Hedging Activities |
|
|
|
|
The Company enters into hedging transactions with major financial institutions to secure a
commodity price for a portion of future production and to reduce the Companys exposure to
fluctuations in the price of oil. The Company does not enter into hedging transactions
for trading purposes. Crude oil hedges are settled based on the average of the reported
settlement prices for West Texas Intermediate crude on the New York Mercantile Exchange
(NYMEX) for each month. The Company had no natural gas hedges as of December 31, 2005 and
2004. The Company uses financially-settled crude oil swaps and zero-cost collars that
provide floor and ceiling prices. The Companys swaps and zero-cost collars are
designated and accounted for as cash flow hedges. |
48
With a financially-settled swap, the counterparty is required to make a payment to
the Company if the settlement price for any settlement period is below the hedged price
for the transaction, and the Company is required to make a payment to the counterparty if
the settlement price for any settlement period is above the hedged price for the
transaction. With a zero-cost collar, the counterparty is required to make a payment to
the Company if the settlement price for any settlement period is below the floor price of
the collar, and the Company is required to make a payment to the counterparty if the
settlement price for any settlement period is above the cap price for the collar. The
Company recognizes the fair value of all derivative instruments as assets or liabilities
on the balance sheet. Changes in the fair value of cash flow hedges are recognized, to
the extent the hedge is effective, in other comprehensive income until the hedged item is
settled and recorded in oil and gas revenue. For the years ended December 31, 2005 and
2004, hedging settlement payments reduced oil revenues by approximately $10.2 million and
$1.6 million, respectively. The Company recorded no gains or losses due to hedge
ineffectiveness, but any gains or losses resulting from hedge ineffectiveness would be
recorded in revenue.
The Company had the following hedging contracts as of December 31, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil Positions |
|
|
Instrument |
|
Strike |
|
Volume (Bbls) |
|
|
Remaining Contract Term |
|
Type |
|
Price (Bbl) |
|
Daily |
|
Total (Bbls) |
01/06 8/06
|
|
Swap
|
|
$ |
39.45 |
|
|
1,000 1,013
|
|
|
274,388 |
|
01/06 8/06
|
|
Collar
|
|
$ |
35.00/$45.60 |
|
|
1,000 1,013
|
|
|
274,388 |
|
Based upon current market prices, the Company expects to transfer approximately $6.9
million of net deferred losses in accumulated other comprehensive loss as of December 31,
2005 to earnings during the next twelve months when the forecasted transactions actually
occur.
(t) |
|
Other Comprehensive Income |
|
|
|
The following table reconciles the change in accumulated other comprehensive income for
the years ended December 31, 2005 and 2004 (amounts in thousands): |
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
Accumulated other comprehensive income, December 31,
2004 and 2003, respectively |
|
$ |
2,884 |
|
|
$ |
264 |
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss), net of tax: |
|
|
|
|
|
|
|
|
Hedging activities: |
|
|
|
|
|
|
|
|
Reclassification adjustment for settled contracts,
net of tax of $3,656 in 2005 and $576 in 2004 |
|
|
6,499 |
|
|
|
981 |
|
Changes in fair value of outstanding hedging
positions,
net of tax of ($6,545) in 2005 and ($1,552) in 2004 |
|
|
(11,637 |
) |
|
|
(2,642 |
) |
Foreign currency translation adjustment |
|
|
(2,662 |
) |
|
|
4,281 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other comprehensive income |
|
|
(7,800 |
) |
|
|
2,620 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive income, December 31,
2005 and 2004, respectively |
|
$ |
(4,916 |
) |
|
$ |
2,884 |
|
|
|
|
|
|
|
|
(2) |
|
Supplemental Cash Flow Information |
The following table includes the Companys supplemental cash flow information for the years ended
December 31, 2005, 2004 and 2003 (amounts in thousands):
49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
Cash paid for interest |
|
$ |
21,152 |
|
|
$ |
23,320 |
|
|
$ |
23,633 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid (received) for income taxes |
|
$ |
10,789 |
|
|
$ |
7,360 |
|
|
$ |
(4,125 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Details of business acquisitions: |
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of assets |
|
$ |
6,627 |
|
|
$ |
25,614 |
|
|
$ |
51,103 |
|
Fair value of liabilities |
|
|
(31 |
) |
|
|
(1,158 |
) |
|
|
(35,270 |
) |
|
|
|
|
|
|
|
|
|
|
Cash paid |
|
|
6,596 |
|
|
|
24,456 |
|
|
|
15,833 |
|
Less cash acquired |
|
|
(163 |
) |
|
|
(95 |
) |
|
|
(1,535 |
) |
|
|
|
|
|
|
|
|
|
|
Net cash paid for acquisitions |
|
$ |
6,433 |
|
|
$ |
24,361 |
|
|
$ |
14,298 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Details of oil and gas property acquisitions: |
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of assets |
|
$ |
11,494 |
|
|
$ |
97,792 |
|
|
$ |
39,509 |
|
Fair value of liabilities |
|
|
(11,494 |
) |
|
|
(82,107 |
) |
|
|
(39,509 |
) |
|
|
|
|
|
|
|
|
|
|
Cash paid |
|
|
|
|
|
|
15,685 |
|
|
|
|
|
Less cash acquired |
|
|
(3,686 |
) |
|
|
(5,009 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash paid for acquisitions |
|
$ |
(3,686 |
) |
|
$ |
10,676 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash investing activity: |
|
|
|
|
|
|
|
|
|
|
|
|
Receivable from sale of affiliate |
|
$ |
1,305 |
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional consideration payable
on acquisitions |
|
$ |
|
|
|
$ |
5,272 |
|
|
$ |
11,263 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note receivable from asset disposition |
|
$ |
|
|
|
$ |
|
|
|
$ |
938 |
|
|
|
|
|
|
|
|
|
|
|
(3) |
|
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 subsidiary ETT for approximately $18.7 million
in cash. The Company reduced the net asset value of ETT by $3.8 million in 2005 to the approximate
sales price of the subsidiary. For the years ended December 31, 2005, 2004 and 2003, revenue from
ETT was approximately $27.7 million, $24.0 million and $21.7 million, respectively, and operating
losses were approximately $5.1 million (inclusive of the $3.8 million loss), $2.1 million and $1.2
million, respectively.
(4) 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 as a result of this transaction.
50
As the result of a tropical storm, one of the Companys 200-foot class liftboats sank in the Gulf
of Mexico on June 30, 2003. The vessel was declared a total loss and the Company received $8
million of insurance proceeds for the vessel. As a result, the Company recorded a gain from the
insurance proceeds of $2.8 million, which is included in other income in the year ended December
31, 2003.
(6) |
|
Acquisitions and Dispositions |
In July 2005, the Company acquired a business for an aggregate purchase price of approximately $1.3
million in cash consideration in order to geographically expand the snubbing services offered by
its well intervention segment. Additional consideration, if any, will be based upon the average
earnings before interest, income taxes, depreciation and amortization expense (EBITDA) over a
three-year period, and will not exceed $0.4 million. This acquisition has been accounted for as a
purchase and the acquired assets and liabilities have been valued at their estimated fair value.
The purchase price preliminarily allocated to net assets was approximately $1.3 million, and no
goodwill was recorded. The results of operations have been included from the acquisition date.
The pro forma effect of operations of the acquisition when included as of the beginning of the
periods presented was not material to the Consolidated Statements of Operations of the Company.
Also in July 2005, the Companys subsidiary, SPN Resources, LLC, acquired additional oil and gas
properties at Galveston 241/255 and High Island A-309 through the acquisition of three offshore
Gulf of Mexico leases. Under the terms of the transaction, the Company acquired the properties and
assumed the related decommissioning liabilities. The Company received $3.7 million in cash and
will invoice the sellers at agreed upon prices as the decommissioning activities (abandonment and
structure removal) are completed. The Company preliminarily recorded notes receivable of
approximately $2.4 million, decommissioning liabilities of $11.5 million and oil and gas producing
assets were recorded at their estimated fair value of $5.4 million. The pro forma effect of
operations of the acquisition when included as of the beginning of the periods presented was not
material to the Consolidated Statements of Operations of the Company.
In 2004, the Companys wholly-owned subsidiary, SPN Resources, LLC, acquired additional oil and gas
properties through the acquisition of interests in 19 offshore Gulf of Mexico leases. Under the
terms of the transactions, the Company acquired the properties and assumed the decommissioning
liabilities. In the aggregate, the Company paid $10.7 million cash, net of amounts received. The
Company recorded decommissioning liabilities of approximately $83.0 million and notes and other
receivables of approximately $12.5 million, and oil and gas producing assets were recorded at their
estimated fair value of approximately $81.2 million.
In 2004, the Company acquired two businesses for an aggregate of $2.8 million in cash consideration
in order to enhance the products and services offered by its rental tools segment and well
intervention segment. These acquisitions were accounted for as purchases. The estimated fair
value of the net assets acquired was approximately $1.0 million in the aggregate, and the excess
purchase price over the fair value of net assets of approximately $1.8 million was allocated to
goodwill. The results of operations have been included from the respective acquisition dates.
Most of the Companys business acquisitions have involved additional contingent consideration based
upon a multiple of the acquired companies respective average EBITDA over a three-year period from
the respective date of acquisition. As of December 31, 2005, the maximum additional consideration
payable for the Companys prior acquisitions was approximately $2.4 million, and will be determined
and payable through 2008. These amounts are not classified as liabilities under generally accepted
accounting principles and are not reflected in the Companys financial statements until the amounts
are fixed and determinable. The Company does not have any other financing arrangements that are
not required under generally accepted accounting principles to be reflected in its financial
statements. When the amounts are determined, they are capitalized as part of the purchase price of
the related acquisition. In January 2005, the Company paid additional consideration of $5.3
million as a result of a prior acquisition, which had been capitalized and accrued in 2004.
51
(7) Property, Plant and Equipment
A summary of property, plant and equipment at December 31, 2005 and 2004 (in thousands) is as
follows:
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
2004 |
|
Buildings and improvements |
|
$ |
58,567 |
|
|
$ |
57,624 |
|
Marine vessels and equipment |
|
|
177,047 |
|
|
|
193,321 |
|
Machinery and equipment |
|
|
394,582 |
|
|
|
342,700 |
|
Automobiles, trucks, tractors and trailers |
|
|
9,428 |
|
|
|
10,248 |
|
Furniture and fixtures |
|
|
13,440 |
|
|
|
11,944 |
|
Construction-in-progress |
|
|
19,054 |
|
|
|
2,498 |
|
Land |
|
|
6,581 |
|
|
|
6,037 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
678,699 |
|
|
|
624,372 |
|
Accumulated depreciation |
|
|
(238,371 |
) |
|
|
(193,038 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net |
|
$ |
440,328 |
|
|
$ |
431,334 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas assets |
|
|
119,986 |
|
|
|
91,104 |
|
Accumulated depletion |
|
|
(25,352 |
) |
|
|
(7,287 |
) |
|
|
|
|
|
|
|
Oil and gas assets, net, under the successful efforts
method of accounting |
|
$ |
94,634 |
|
|
$ |
83,817 |
|
|
|
|
|
|
|
|
Amounts of property, plant and equipment leased to third parties at December 31, 2005 and 2004 were
not material. Depreciation expense (excluding depletion, amortization and accretion) was
approximately $68.6 million, $57.1 million and $48.5 million for the years ended December 31, 2005,
2004 and 2003, respectively.
(8) |
|
Investments in Affiliates |
On November 2, 2005, the Companys investment in affiliate sold substantially all of its assets.
The Company received $12.5 million as a result of the sale and has recorded receivables of
approximately $1.3 million for the remaining proceeds to be distributed. The Company reduced the
value of this investment by approximately $1.3 million during 2005 in anticipation of this sale.
The Companys long-term debt as of December 31, 2005 and 2004 consisted of the following (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
2004 |
|
Senior Notes interest payable semiannually
at 8.875%, due May 2011 |
|
$ |
200,000 |
|
|
$ |
200,000 |
|
Term Loans repaid in November 2005 |
|
|
|
|
|
|
38,500 |
|
Revolver interest payable monthly at floating rate,
due in October 2008 |
|
|
|
|
|
|
|
|
U.S. Government guaranteed long-term financing interest
payable semianually at 6.45%, due in semiannual
installments through June 2027 |
|
|
17,406 |
|
|
|
18,216 |
|
|
|
|
|
|
|
|
|
|
|
217,406 |
|
|
|
256,716 |
|
Less current portion |
|
|
810 |
|
|
|
11,810 |
|
|
|
|
|
|
|
|
Long-term debt |
|
$ |
216,596 |
|
|
$ |
244,906 |
|
|
|
|
|
|
|
|
52
Effective October 31, 2005, the Company amended its bank credit facility to convert the existing
term loans and revolving credit facility into a single $150 million revolving credit facility, with
an option to increase it to $250 million. Any balance outstanding on the revolving credit facility
is due on October 31, 2008. At December 31, 2005, the Company had no balance on this bank credit
facility. The credit facility bears 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 capital expenditures, its 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. The Company also has letters of credit outstanding of approximately $18.6 million at
December 31, 2005, which reduce the borrowing availability under its revolving credit facility. At
December 31, 2005, the Company was in compliance with all such covenants. The Company wrote-off
debt acquisition costs of approximately $224,000 due to the repayment of its term loans. This
write-off is included in interest expense in 2005.
The Company has $17.4 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, which began December 3, 2002, and matures
on 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. This
long-term financing ranks equally with the bank credit facility as both are secured by unique
assets.
The Company also has outstanding $200 million of 8 7/8% unsecured senior notes due 2011. The
indenture governing the notes requires semi-annual interest payments, on every November
15th and May 15th through the maturity date of May 15, 2011. The Company may
redeem the notes during the 12-month period commencing May 15, 2006 at 104.438% of the principal
amount redeemed. The indenture governing the senior notes contains certain covenants that, among
other things, prevent the Company from incurring additional debt, paying dividends or making other
distributions, unless its ratio of cash flow to interest expense is at least 2.25 to 1, except that
the Company may incur debt in addition to the senior notes in an amount equal to 30% of its net
tangible assets as defined, which was approximately $208 million at December 31, 2005. The
indenture also contains covenants that restrict the Companys ability to create certain liens, sell
assets, or enter into certain mergers or acquisitions.
Annual maturities of long-term debt for each of the five fiscal years following December 31, 2005
are as follows (in thousands):
|
|
|
|
|
2006 |
|
$ |
810 |
|
2007 |
|
|
810 |
|
2008 |
|
|
810 |
|
2009 |
|
|
810 |
|
2010 |
|
|
810 |
|
Thereafter |
|
|
213,356 |
|
|
|
|
|
Total |
|
$ |
217,406 |
|
|
|
|
|
The components of income tax expense (benefit) for the years ended December 31, 2005, 2004 and 2003
are as follows (in thousands):
53
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
Current |
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
$ |
30,745 |
|
|
$ |
87 |
|
|
$ |
515 |
|
State |
|
|
897 |
|
|
|
415 |
|
|
|
245 |
|
Foreign |
|
|
6,087 |
|
|
|
5,320 |
|
|
|
2,365 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
37,729 |
|
|
|
5,822 |
|
|
|
3,125 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred |
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
|
1,895 |
|
|
|
17,569 |
|
|
|
14,561 |
|
State |
|
|
94 |
|
|
|
105 |
|
|
|
1,220 |
|
Foreign |
|
|
(1,547 |
) |
|
|
(2,440 |
) |
|
|
(598 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
442 |
|
|
|
15,234 |
|
|
|
15,183 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
38,171 |
|
|
$ |
21,056 |
|
|
$ |
18,308 |
|
|
|
|
|
|
|
|
|
|
|
Income tax expense differs from the amounts computed by applying the U.S. Federal income tax rate
of 35% to income before income taxes as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
Computed expected tax expense |
|
$ |
37,111 |
|
|
$ |
19,918 |
|
|
$ |
17,088 |
|
Increase resulting from: |
|
|
|
|
|
|
|
|
|
|
|
|
State and foreign income taxes |
|
|
241 |
|
|
|
178 |
|
|
|
478 |
|
Other |
|
|
819 |
|
|
|
960 |
|
|
|
742 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense |
|
$ |
38,171 |
|
|
$ |
21,056 |
|
|
$ |
18,308 |
|
|
|
|
|
|
|
|
|
|
|
The significant components of deferred income taxes at December 31, 2005 and 2004 are as follows
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
2004 |
|
Deferred tax assets: |
|
|
|
|
|
|
|
|
Allowance for doubtful accounts |
|
$ |
1,793 |
|
|
$ |
776 |
|
Alternative minimum tax credit and net
operating loss carryforward |
|
|
8,198 |
|
|
|
12,358 |
|
Decommissioning liability |
|
|
45,106 |
|
|
|
42,187 |
|
Other |
|
|
9,476 |
|
|
|
5,133 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax assets |
|
|
64,573 |
|
|
|
60,454 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities: |
|
|
|
|
|
|
|
|
Property, plant and equipment |
|
|
137,185 |
|
|
|
133,710 |
|
Note receivable |
|
|
11,668 |
|
|
|
14,103 |
|
Other |
|
|
13,707 |
|
|
|
16,013 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities |
|
|
162,560 |
|
|
|
163,826 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability |
|
$ |
97,987 |
|
|
$ |
103,372 |
|
|
|
|
|
|
|
|
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 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.
54
As of December 31, 2005, the Company has not established a valuation allowance for its deferred tax
assets. The Company believes that it is more likely than not that the tax assets will be realized
because of the reversal of accelerated tax depreciation and future taxable income.
As of December 31, 2005, the Company has an estimated $5.3 million foreign tax credit carryforward
with expiration dates from 2011 through 2014. As of December 31, 2005, the Company also has
various state net operating loss carryforwards of an estimated $56 million with expiration dates
from 2013 through 2017.
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, 2005, the undistributed earnings of the Companys foreign subsidiaries were
approximately $22.9 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.
The American Jobs Creation Act of 2004 was passed on October 22, 2004. This legislation allows,
under certain conditions, a one-time tax deduction of 85% of certain foreign earnings that are
repatriated prior to the end of the Companys fiscal 2005 year. The deduction would result in a
5.25% federal tax rate on the repatriated earnings. As of December 31, 2004, the Company had not
determined whether earnings will be repatriated or an estimate of the possible United States
federal and state income tax expense related to any potential repatriation. In 2005, the
Company analyzed foreign earnings that qualified for the temporary repatriation. As a result of
the analysis, the Company has determined that there was no significant benefit to the Company from
this incentive because foreign tax credits would be available to reduce the impact of repatriation
of foreign earnings in future years. Accordingly, the Company did not repatriate any foreign
earnings in 2005.
(11) |
|
Stockholders Equity |
In December 2005, the Companys Compensation Committee of the Board of Directors granted 24,000
shares of restricted stock to its President. The restricted stock vests in three equal
installments on January 2, 2006, 2007 and 2008. The Company expensed approximately $178,000 in
2005 based on the share price of $22.24 on the date of grant and will expense approximately
$178,000 in 2006 and 2007, as the remaining shares vest.
In October 2004, the Company sold 9,696,627 shares of common stock that generated net proceeds
(before any exercise of the underwriters over-allotment option) of approximately $113 million,
after deducting underwriting discounts and commissions and the estimated offering expenses. The
Company used 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. In November 2004,
an additional 1,454,494 shares of the Companys common stock were issued pursuant to the exercise
of the underwriters over-allotment option generating net proceeds of approximately $17 million,
after deducting underwriting discounts and commissions.
In 2004, the Superior Energy Services, Inc. 2004 Directors Restricted Stock Units Plan was approved
by the Companys stockholders. This plan provides each non-employee director is granted a number
of restricted stock units having an aggregate value of $30,000, with the exact number of units
determined by dividing $30,000 by the fair market value of the Companys common stock on the day of
the annual stockholders meeting. In addition, upon any persons initial election or appointment
as an eligible director, other than at an annual stockholders meeting, such person will receive a
pro forma number of restricted stock units based on the number of full calendar months between the
date of grant and the first anniversary of the previous 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, 19,998 restricted stock units are outstanding at December 31, 2005.
The Company maintains various stock incentive plans, including the 2002 Stock Incentive Plan (2002
Incentive Plan), the 1999 Stock Incentive Plan (1999 Incentive Plan) and the 1995 Stock Incentive
Plan (1995 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 2002 Incentive Plan, the 1999 Incentive Plan and the 1995 Incentive Plan, the Company may
grant incentive stock options, non-qualified stock options, restricted
55
stock, stock awards or any
combination thereof to Eligible Participants for up to 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 2002 Incentive Plan, 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 are vested.
A summary of stock options granted under the incentive plans for the years ended December 31, 2005,
2004 and 2003 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
Number of |
|
|
Average |
|
|
Number of |
|
|
Average |
|
|
Number of |
|
|
Average |
|
|
|
Shares |
|
|
Price |
|
|
Shares |
|
|
Price |
|
|
Shares |
|
|
Price |
|
Outstanding at beginning
of year |
|
|
5,797,295 |
|
|
$ |
8.43 |
|
|
|
5,628,000 |
|
|
$ |
7.53 |
|
|
|
5,518,516 |
|
|
$ |
7.33 |
|
Granted |
|
|
863,500 |
|
|
$ |
17.46 |
|
|
|
1,490,000 |
|
|
$ |
10.66 |
|
|
|
538,000 |
|
|
$ |
8.94 |
|
Exercised |
|
|
(2,709,624 |
) |
|
$ |
6.94 |
|
|
|
(1,196,060 |
) |
|
$ |
7.01 |
|
|
|
(271,913 |
) |
|
$ |
6.72 |
|
Forfeited |
|
|
(57,538 |
) |
|
$ |
10.23 |
|
|
|
(124,645 |
) |
|
$ |
8.14 |
|
|
|
(156,603 |
) |
|
$ |
7.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at end of year |
|
|
3,893,633 |
|
|
$ |
11.44 |
|
|
|
5,797,295 |
|
|
$ |
8.43 |
|
|
|
5,628,000 |
|
|
$ |
7.53 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at end of year |
|
|
3,759,721 |
|
|
$ |
11.53 |
|
|
|
5,328,741 |
|
|
$ |
8.37 |
|
|
|
4,248,244 |
|
|
$ |
7.08 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Available for future grants |
|
|
3,229,784 |
|
|
|
|
|
|
|
35,746 |
|
|
|
|
|
|
|
1,401,101 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average fair value of grants
during the year |
|
|
|
|
|
$ |
7.47 |
|
|
|
|
|
|
$ |
6.22 |
|
|
|
|
|
|
$ |
3.59 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
A summary of information regarding stock options outstanding at December 31, 2005 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 |
|
|
33,000 |
|
|
2.7 years |
|
$ |
5.36 |
|
|
|
33,000 |
|
|
$ |
5.36 |
|
$7.06 - $9.00 |
|
|
744,610 |
|
|
6.1 years |
|
$ |
8.38 |
|
|
|
619,031 |
|
|
$ |
8.30 |
|
$9.10 - $12.45 |
|
|
2,252,523 |
|
|
7.6 years |
|
$ |
10.23 |
|
|
|
2,244,190 |
|
|
$ |
10.23 |
|
$12.50 - $17.46 |
|
|
863,500 |
|
|
9.5 years |
|
$ |
17.46 |
|
|
|
863,500 |
|
|
$ |
17.46 |
|
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. The Company provides a discretionary match, not to exceed 5% of an employees salary. The
Company made contributions of approximately $1.9 million, $1.7 million and $1.6 million, in 2005,
2004 and 2003, 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 after the employee terminates, based on their
distribution election 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,
2005, the liability of the Company to the participants was approximately $1.5 million and is
recorded in Other Long-Term Liabilities, which reflects the accumulated participant deferrals and
earnings as of that date. The Company makes
56
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, 2005, the deferred
contribution plan asset was approximately $1.4 million and is recorded in Other Long-Term Assets.
(13) |
|
Commitments and Contingencies |
The Company leases certain office, service and assembly facilities under operating leases. The
leases expire at various dates over the next several years. Total rent expense was approximately
$4.3 million in 2005, $4.2 million in 2004 and $2.3 million in 2003. Future minimum lease payments
under non-cancelable leases for the five years
ending December 31, 2006 through 2010 and thereafter are as follows: $6,360,000, $4,837,000,
$2,723,000, $1,667,000, $1,137,000 and $14,181,000, respectively. Future minimum lease payments
receivable under non-cancelable sub-leases for the years ending December 31, 2006 through 2008 are
as follows: $535,000, $592,000, and $49,000, 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.
Business Segments
The Companys reportable segments are as follows: well intervention, rental tools, marine, other
oilfield services and oil and gas. The first four segments offer products and services within the
oilfield services industry. The well intervention segment provides plug and abandonment services,
coiled tubing services, well pumping and stimulation services, data acquisition services, gas lift
services, electric wireline services, hydraulic drilling and workover services, well control
services, engineering support, technical analysis and mechanical wireline services that perform a
variety of ongoing maintenance and repairs to producing wells, as well as modifications to enhance
the production capacity and life span of the well. The rental tools segment rents and sells
specialized equipment for use with onshore and offshore oil and gas well drilling, completion,
production and workover activities. The marine segment operates liftboats for production service
activities, as well as oil and gas production facility maintenance, construction operations and
platform removals. The other oilfield services segment provides contract operations and
maintenance services, transportation and logistics services, offshore oil and gas cleaning
services, oilfield waste treatment services, dockside cleaning of items, including supply boats,
cutting boxes, and process equipment and drilling instrumentation equipment. The oil and gas
segment acquires mature oil and gas properties and produces and sells any remaining economic oil
and gas reserves prior to the Companys other segments providing decommissioning services. Oil and
gas eliminations represent products and services provided to the oil and gas segment by the
Companys four 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.
Summarized financial information concerning the Companys segments as of December 31, 2005, 2004
and 2003 and for the years then ended is shown in the following tables (in thousands):
57
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
Oil & Gas |
|
|
|
|
Well |
|
Rental |
|
|
|
|
|
Oilfield |
|
|
|
|
|
Eliminations |
|
Consolid. |
2005 |
|
Interven. |
|
Tools |
|
Marine |
|
Services |
|
Oil & Gas |
|
& Unallocated |
|
Total |
|
|
|
Revenues |
|
$ |
248,576 |
|
|
$ |
243,536 |
|
|
$ |
87,267 |
|
|
$ |
91,033 |
|
|
$ |
78,911 |
|
|
$ |
(13,989 |
) |
|
$ |
735,334 |
|
Costs of services |
|
|
142,334 |
|
|
|
82,562 |
|
|
|
47,989 |
|
|
|
71,304 |
|
|
|
45,804 |
|
|
|
(13,989 |
) |
|
|
376,004 |
|
Depreciation, depletion,
amortization and accretion |
|
|
14,481 |
|
|
|
42,445 |
|
|
|
8,214 |
|
|
|
3,654 |
|
|
|
20,494 |
|
|
|
|
|
|
|
89,288 |
|
General and administrative |
|
|
53,037 |
|
|
|
54,533 |
|
|
|
9,889 |
|
|
|
17,990 |
|
|
|
5,540 |
|
|
|
|
|
|
|
140,989 |
|
Reduction in value of assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,850 |
|
|
|
2,144 |
|
|
|
|
|
|
|
6,994 |
|
Gain on sale of liftboats |
|
|
|
|
|
|
|
|
|
|
3,544 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,544 |
|
Operating income |
|
|
38,724 |
|
|
|
63,996 |
|
|
|
24,719 |
|
|
|
(6,765 |
) |
|
|
4,929 |
|
|
|
|
|
|
|
125,603 |
|
Interest expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(21,862 |
) |
|
|
(21,862 |
) |
Interest income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,160 |
|
|
|
1,041 |
|
|
|
2,201 |
|
Equity in earnings of affiliates |
|
|
|
|
|
|
1,339 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,339 |
|
Reduction in value of investment |
|
|
|
|
|
|
(1,250 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,250 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income
taxes |
|
$ |
38,724 |
|
|
$ |
64,085 |
|
|
$ |
24,719 |
|
|
$ |
(6,765 |
) |
|
$ |
6,089 |
|
|
$ |
(20,821 |
) |
|
$ |
106,031 |
|
|
|
|
Identifiable assets |
|
$ |
280,595 |
|
|
$ |
405,527 |
|
|
$ |
203,718 |
|
|
$ |
52,401 |
|
|
$ |
147,667 |
|
|
$ |
7,342 |
|
|
$ |
1,097,250 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
$ |
22,524 |
|
|
$ |
70,227 |
|
|
$ |
10,399 |
|
|
$ |
2,323 |
|
|
$ |
19,693 |
|
|
|
|
|
|
$ |
125,166 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
Oil & Gas |
|
|
|
|
Well |
|
Rental |
|
|
|
|
|
Oilfield |
|
|
|
|
|
Eliminations |
|
Consolid. |
2004 |
|
Interven. |
|
Tools |
|
Marine |
|
Services |
|
Oil & Gas |
|
& Unallocated |
|
Total |
|
|
|
Revenues |
|
$ |
211,820 |
|
|
$ |
170,064 |
|
|
$ |
69,808 |
|
|
$ |
83,870 |
|
|
$ |
37,008 |
|
|
$ |
(8,231 |
) |
|
$ |
564,339 |
|
Costs of services |
|
|
122,065 |
|
|
|
57,353 |
|
|
|
49,581 |
|
|
|
67,793 |
|
|
|
21,547 |
|
|
|
(8,231 |
) |
|
|
310,108 |
|
Depreciation, depletion,
amortization and accretion |
|
|
13,546 |
|
|
|
32,527 |
|
|
|
7,362 |
|
|
|
3,889 |
|
|
|
10,013 |
|
|
|
|
|
|
|
67,337 |
|
General and administrative |
|
|
43,912 |
|
|
|
42,165 |
|
|
|
7,085 |
|
|
|
14,791 |
|
|
|
2,652 |
|
|
|
|
|
|
|
110,605 |
|
Operating income |
|
|
32,297 |
|
|
|
38,019 |
|
|
|
5,780 |
|
|
|
(2,603 |
) |
|
|
2,796 |
|
|
|
|
|
|
|
76,289 |
|
Interest expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(22,476 |
) |
|
|
(22,476 |
) |
Interest income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,648 |
|
|
|
118 |
|
|
|
1,766 |
|
Equity in earnings of affiliates |
|
|
|
|
|
|
1,329 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,329 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income
taxes |
|
$ |
32,297 |
|
|
$ |
39,348 |
|
|
$ |
5,780 |
|
|
$ |
(2,603 |
) |
|
$ |
4,444 |
|
|
$ |
(22,358 |
) |
|
$ |
56,908 |
|
|
|
|
Identifiable assets |
|
$ |
258,870 |
|
|
$ |
357,762 |
|
|
$ |
184,928 |
|
|
$ |
54,561 |
|
|
$ |
141,179 |
|
|
$ |
6,613 |
|
|
$ |
1,003,913 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
$ |
11,124 |
|
|
$ |
50,687 |
|
|
$ |
5,523 |
|
|
$ |
1,611 |
|
|
$ |
5,180 |
|
|
|
|
|
|
$ |
74,125 |
|
58
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
Well |
|
Rental |
|
|
|
|
|
Oilfield |
|
|
|
|
|
|
|
|
|
Consolid. |
2003 |
|
Interven. |
|
Tools |
|
Marine |
|
Services |
|
Oil & Gas |
|
Unallocated |
|
Total |
|
|
|
Revenues |
|
$ |
187,271 |
|
|
$ |
141,362 |
|
|
$ |
70,370 |
|
|
$ |
100,881 |
|
|
$ |
741 |
|
|
$ |
|
|
|
$ |
500,625 |
|
Costs of services |
|
|
111,330 |
|
|
|
46,119 |
|
|
|
50,314 |
|
|
|
81,513 |
|
|
|
331 |
|
|
|
|
|
|
|
289,607 |
|
Depreciation, depletion,
amortization and accretion |
|
|
12,231 |
|
|
|
25,696 |
|
|
|
6,665 |
|
|
|
4,130 |
|
|
|
131 |
|
|
|
|
|
|
|
48,853 |
|
General and administrative |
|
|
39,572 |
|
|
|
33,457 |
|
|
|
7,122 |
|
|
|
14,643 |
|
|
|
28 |
|
|
|
|
|
|
|
94,822 |
|
Operating income |
|
|
24,138 |
|
|
|
36,090 |
|
|
|
6,269 |
|
|
|
595 |
|
|
|
251 |
|
|
|
|
|
|
|
67,343 |
|
Interest expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(22,477 |
) |
|
|
(22,477 |
) |
Interest income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
51 |
|
|
|
158 |
|
|
|
209 |
|
Other income |
|
|
|
|
|
|
|
|
|
|
2,762 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,762 |
|
Equity in earnings of affiliates |
|
|
|
|
|
|
985 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
985 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income
taxes |
|
$ |
24,138 |
|
|
$ |
37,075 |
|
|
$ |
9,031 |
|
|
$ |
595 |
|
|
$ |
302 |
|
|
$ |
(22,319 |
) |
|
$ |
48,822 |
|
|
|
|
Identifiable assets |
|
$ |
224,022 |
|
|
$ |
314,122 |
|
|
$ |
181,752 |
|
|
$ |
64,421 |
|
|
$ |
41,315 |
|
|
$ |
7,231 |
|
|
$ |
832,863 |
|
Capital expenditures |
|
$ |
15,248 |
|
|
$ |
30,192 |
|
|
$ |
2,043 |
|
|
$ |
2,692 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
50,175 |
|
Geographic Segments
The Company attributes revenue to various countries based on the location of where services are
performed or the destination of the sale of products. 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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
Long-Lived Assets |
|
|
|
Years Ended December 31, |
|
|
December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
2005 |
|
|
2004 |
|
United States |
|
$ |
636,062 |
|
|
$ |
476,771 |
|
|
$ |
443,936 |
|
|
$ |
492,602 |
|
|
$ |
479,812 |
|
Other Countries |
|
|
99,272 |
|
|
|
87,568 |
|
|
|
56,689 |
|
|
|
42,360 |
|
|
|
35,339 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
735,334 |
|
|
$ |
564,339 |
|
|
$ |
500,625 |
|
|
$ |
534,962 |
|
|
$ |
515,151 |
|
|
|
|
|
|
(15) |
|
Interim Financial Information (Unaudited) |
The following is a summary of consolidated interim financial information for the years ended
December 31, 2005 and 2004 (amounts in thousands, except per share data):
59
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31 |
|
|
June 30 |
|
|
Sept. 30 |
|
|
Dec. 31 |
|
2004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
116,459 |
|
|
$ |
137,545 |
|
|
$ |
152,500 |
|
|
$ |
157,835 |
|
Gross profit |
|
|
49,754 |
|
|
|
60,401 |
|
|
|
70,089 |
|
|
|
73,987 |
|
Net income |
|
|
3,564 |
|
|
|
8,714 |
|
|
|
11,288 |
|
|
|
12,286 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.05 |
|
|
$ |
0.12 |
|
|
$ |
0.15 |
|
|
$ |
0.16 |
|
Diluted |
|
|
0.05 |
|
|
|
0.12 |
|
|
|
0.15 |
|
|
|
0.16 |
|
(16) |
|
Supplementary Oil and Natural Gas Disclosures (Unaudited) |
The Companys December 31, 2005 and 2004 estimates of proved reserves are based on reserve reports
prepared by DeGolyer and MacNaughton, independent petroleum engineers. The estimates of proved
reserves at December 31, 2003 are based on internal reports. 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:
60
|
|
|
|
|
|
|
|
|
|
|
Crude Oil |
|
|
Natural Gas |
|
|
|
(Mbbls) |
|
|
(Mmcf) |
|
Proved-developed and undeveloped reserves: |
|
|
|
|
|
|
|
|
December 31, 2002 |
|
|
|
|
|
|
|
|
Purchase of reserves in place |
|
|
193 |
|
|
|
3,304 |
|
Revisions |
|
|
|
|
|
|
(1 |
) |
Production |
|
|
(3 |
) |
|
|
(79 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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) |
|
|
1,036 |
|
|
|
(5,294 |
) |
Production |
|
|
(1,221 |
) |
|
|
(3,323 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2005 |
|
|
9,103 |
|
|
|
23,688 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved-developed reserves: |
|
|
|
|
|
|
|
|
December 31, 2003 |
|
|
64 |
|
|
|
3,190 |
|
December 31, 2004 |
|
|
7,731 |
|
|
|
25,542 |
|
December 31, 2005 |
|
|
7,554 |
|
|
|
21,703 |
|
(1) The
downward revisions in 2005 were primarily attributable to three
factors: 1) the Company determined that it would not undertake
four previously planned behind pipe recompletions, 2) one well
was plugged and abandoned after experiencing continuing mechanical
difficulties, and 3) production rates from several wells after
their acquisition by the Company did not support the reserve level
initially established.
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, 2005, 2004 and 2003 are as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended December 31, |
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
Acquisition of properties proved |
|
$ |
9,015 |
|
|
$ |
81,356 |
|
|
$ |
5,041 |
|
Development costs |
|
|
19,867 |
|
|
|
4,707 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs incurred |
|
$ |
28,882 |
|
|
$ |
86,063 |
|
|
$ |
5,041 |
|
|
|
|
|
|
|
|
|
|
|
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.
61
The Company believes that the following factors should be taken into account in reviewing the
following information: (1) future costs and selling prices will probably 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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
Future cash inflows |
|
$ |
792,246 |
|
|
$ |
587,277 |
|
|
$ |
26,002 |
|
Future production costs |
|
|
(155,282 |
) |
|
|
(148,610 |
) |
|
|
(12,603 |
) |
Future development and abandonment costs |
|
|
(195,415 |
) |
|
|
(153,230 |
) |
|
|
(6,641 |
) |
Future income tax expense |
|
|
(171,058 |
) |
|
|
(119,567 |
) |
|
|
(2,748 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows after income taxes |
|
|
270,491 |
|
|
|
165,870 |
|
|
|
4,010 |
|
10% annual discount for estimated timing of cash flows |
|
|
65,386 |
|
|
|
29,363 |
|
|
|
20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Standardized measure of discounted future net cash flows |
|
$ |
205,105 |
|
|
$ |
136,507 |
|
|
$ |
3,990 |
|
|
|
|
|
|
|
|
|
|
|
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, 2005, 2004 and 2003 is as
follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
Beginning of the period |
|
$ |
136,507 |
|
|
$ |
3,990 |
|
|
$ |
|
|
Sales and transfers of oil and natural gas produced,
net of production costs |
|
|
(34,563 |
) |
|
|
(15,467 |
) |
|
|
(470 |
) |
Net changes in prices and production costs |
|
|
156,992 |
|
|
|
949 |
|
|
|
(1 |
) |
Revisions of quantity estimates |
|
|
4,314 |
|
|
|
46,040 |
|
|
|
(8 |
) |
Development costs incurred |
|
|
19,867 |
|
|
|
4,707 |
|
|
|
|
|
Changes in estimated development costs |
|
|
(46,113 |
) |
|
|
(99,253 |
) |
|
|
(5,496 |
) |
Purchase and sales of reserves in place |
|
|
18,408 |
|
|
|
282,935 |
|
|
|
12,552 |
|
Changes in production rates (timing) and other |
|
|
(25,536 |
) |
|
|
(3,238 |
) |
|
|
(13 |
) |
Accretion of discount |
|
|
22,123 |
|
|
|
656 |
|
|
|
|
|
Net change in income taxes |
|
|
(46,894 |
) |
|
|
(84,812 |
) |
|
|
(2,574 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase |
|
|
68,598 |
|
|
|
132,517 |
|
|
|
3,990 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of period |
|
$ |
205,105 |
|
|
$ |
136,507 |
|
|
$ |
3,990 |
|
|
|
|
|
|
|
|
|
|
|
62
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.
The December 31, 2003 amount was estimated by the Company using a period end oil price of $32.55
per bbl and $6.14 per thousand cubic feet (mcf) for natural gas. The Company had no oil and gas
holdings prior to 2003. Spot prices as of February 28, 2006 were $6.71 per million British Thermal
units for natural gas and $61.41 per bbl for crude oil.
(17) Accounting Pronouncements |
In December 2004, the Financial Accounting Standards Board revised its Statement of Financial
Accounting Standards No. 123 (FAS No. 123R), Accounting for Stock Based Compensation. Under FAS
No. 123R, companies will be required to recognize as expense the estimated fair value of all
share-based payments to employees, including the fair value of employee stock options. This
expense will be recognized over the period during which the employee is required to provide service
in exchange for the award. Pro forma disclosure of the estimated expense impact of such awards is
no longer an alternative to expense recognition in the financial statements. FAS No. 123R is
effective for public companies in the first annual period beginning after June 15, 2005, and
accordingly, the Company will adopt the provisions of FAS No. 123R effective January 1, 2006. The
Comapny anticipates using the modified prospective application transition method, which does not
include restatement of prior periods. The Company expects to record approximately $89,000 of
compensation expense in 2006 due to the adoption of FAS No. 123R for share-based awards granted
prior to January 1, 2006. The Company expects the effect of the adoption on future share-based
awards to be consistent with the disclosure of pro forma net income and earnings per share as
displayed in note 1 of its consolidated financial statements.
In May 2005, the Financial Accounting Standards Board issued Statement of Financial Accounting
Standards No. 154 (FAS No. 154), Accounting Changes and Error Corrections. This Statement
replaces APB Opinion No. 20, Accounting Changes and FASB Statement No. 3, Reporting Accounting
Changes in Interim Financial Statements. FAS No. 154 provides guidance on the accounting for and
reporting of accounting changes and error corrections. It establishes, unless impracticable,
retrospective application as the required method for reporting all changes in accounting principle
in the absence of explicit transition requirements of new pronouncements. FAS No. 154 is effective
for accounting changes and error corrections made in fiscal years beginning after December 15,
2005.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure
None.
Item 9A. Controls and Procedures
Disclosure 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 recorded, processed, summarized and
reported within the time periods specified in the Securities and Exchange Commissions rules and
forms, and that such information is accumulated and communicated to our management, including our
principal executive officer and principal financial officer, as appropriate, to allow timely
decisions regarding required disclosure based closely on the definition of disclosure controls and
procedures in Rule 13a-15(e) of the Securities Exchange Act of 1934.
63
Managements Annual Report on Internal Control Over Financial Reporting
As of December 31, 2005, our management, including our principal executive officer and principal
financial officer, evaluated the effectiveness of the design and operation of our disclosure
controls and procedures pursuant to Rule 13a-15(e) of the Securities Exchange Act of 1934. Based
on this evaluation, our principal executive officer and principal financial officer concluded that
our disclosure controls and procedures as of December 31, 2005 are effective in providing
reasonable assurance that the information required to be disclosed by us in reports filed under the
Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time
periods specified in the SECs rules and forms. Managements report and the independent registered
public accounting firms attestation report are included in 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.
Changes in Internal Control Over Financial Reporting
There has been no change in our internal control over financial reporting during the quarter ended
December 31, 2005 that has materially affected, or is reasonably likely to materially affect, our
internal control over financial reporting.
Item 9B. Other Information
None.
64
PART III
Item 10. Directors and Executive Officers of the Registrant
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
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.
65
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, 2005 and 2004 |
|
|
|
Consolidated Statements of Operations for the years ended December 31, 2005, 2004 and 2003 |
|
|
|
Consolidated Statements of Changes in Stockholders Equity for the years ended December 31,
2005, 2004 and 2003 |
|
|
|
Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 and 2003 |
|
|
|
Notes to Consolidated Financial Statements |
|
(2) |
|
Financial Statement Schedule |
|
|
|
Schedule II Valuation and Qualifying Accounts for the years ended December 31, 2005, 2004 and
2003 |
|
|
|
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 |
|
|
|
The following exhibits are filed as part of this Annual Report on Form 10-K, or where indicated
were previously filed and are hereby incorporated by reference: |
|
|
|
See the Index to Exhibits beginning on page E-1. |
66
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. |
|
|
|
|
|
|
|
By:
|
|
/s/ Terence E. Hall |
|
|
|
|
|
|
|
|
|
Terence E. Hall |
|
|
|
|
Chairman of the Board and |
|
|
|
|
Chief Executive Officer |
Pursuant to the requirements of Section 13 or 15(d) 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
|
|
March 10, 2006 |
|
|
Chief Executive Officer |
|
|
|
|
(Principal Executive Officer) |
|
|
|
|
|
|
|
/s/ Robert S. Taylor
|
|
Executive Vice President, Treasurer and
|
|
March 10, 2006 |
|
|
Chief Financial Officer |
|
|
|
|
(Principal Financial and Accounting Officer) |
|
|
|
|
|
|
|
/s/ Enoch L. Dawkins
|
|
Director
|
|
March 10, 2006 |
|
|
|
|
|
|
|
|
|
|
/s/ James M. Funk
|
|
Director
|
|
March 10, 2006 |
|
|
|
|
|
|
|
|
|
|
/s/ Ernest E. Howard, III
|
|
Director
|
|
March 10, 2006 |
|
|
|
|
|
|
|
|
|
|
/s/ Richard A. Pattarozzi
|
|
Director
|
|
March 10, 2006 |
|
|
|
|
|
|
|
|
|
|
/s/ Justin L. Sullivan
|
|
Director
|
|
March 10, 2006 |
|
|
|
|
|
67
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Schedule II Valuation and Qualifying Accounts
Years Ended December 31, 2005, 2004 and 2003
(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, 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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2003: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for doubtful accounts |
|
$ |
4,617 |
|
|
$ |
2,359 |
|
|
$ |
|
|
|
$ |
696 |
|
|
$ |
6,280 |
|
68
|
|
|
Exhibit No. |
|
Description |
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)). |
|
|
|
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). |
|
|
|
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). |
|
|
|
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). |
E-1
|
|
|
Exhibit No. |
|
Description |
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
|
|
Superior Energy Services, Inc.s 2004 Directors
Restricted Stock Units Plan (incorporated herein by
reference to Appendix A to the Companys Definitive
Proxy Statement dated April 16, 2004). |
|
|
|
10.6
|
|
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). |
|
|
|
10.7
|
|
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). |
|
|
|
10.8
|
|
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). |
|
|
|
10.9
|
|
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). |
|
|
|
10.10
|
|
Form of Performance Share Unit Award Agreement
(incorporated herein by reference to Exhibit 10.1 to
the Companys Form 8-K filed June 30, 2005). |
|
|
|
10.11
|
|
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 June 30, 2005). |
|
|
|
10.12
|
|
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). |
E-2
|
|
|
Exhibit No. |
|
Description |
10.13
|
|
Retention Agreement, effective as of December 14, 2005,
by and between the Company and Kenneth L. Blanchard
(incorporated herein by reference to Exhibit 10.1 to
the Companys Form 8-K filed December 19, 2005). |
|
|
|
10.14
|
|
Restricted Stock Agreement, effective as of December
14, 2005, by and between the Company and Kenneth L.
Blanchard (incorporated herein by reference to Exhibit
10.2 to the Companys Form 8-K filed December 19,
2005). |
|
|
|
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). |
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21.1*
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Subsidiaries of the Company. |
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23.1*
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Consent of KPMG LLP. |
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23.2*
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Consent of DeGolyer and MacNaughton. |
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31.1*
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Officers certification pursuant to Rules 13a-14(a) and
15d-14(a) under the Securities Exchange Act of 1934, as
amended. |
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31.2*
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Officers certification pursuant to Rules 13a-14(a) and
15d-14(a) under the Securities Exchange Act of 1934, as
amended. |
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32.1*
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Officers certification pursuant to Section 1350 of
Title 18 of the U.S. Code. |
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32.2*
|
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Officers certification pursuant to Section 1350 of
Title 18 of the U.S. Code. |
E-3
exv21w1
EXHIBIT 21.1
SUPERIOR ENERGY SERVICES, INC.
List of Subsidiaries
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STATE OF JURISDICTION OF |
NAME |
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INCORPORATION OR ORGANIZATION |
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1105 Peters Road, L.L.C.
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Louisiana |
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Ace Rental Tools, L.L.C.
|
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Louisiana |
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Blowout Tools, Inc.
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Texas |
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Concentric Pipe and Tool Rentals, L.L.C.
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Louisiana |
|
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Connection Technology, L.L.C.
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Louisiana |
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CSI Technologies, LLC
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Texas |
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Drilling Logistics, L.L.C.
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Louisiana |
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F & F Wireline Services, L.L.C.
|
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Louisiana |
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Fastorq, L.L.C.
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Louisiana |
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H.B Rentals, L.C.
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Louisiana |
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International Snubbing Services, L.L.C.
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Louisiana |
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J.R.B. Consultants, Inc.
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Texas |
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Non-Magnetic Rental Tools, L.L.C.
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Louisiana |
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Oil Stop, L.L.C.
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Louisiana |
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Premier Oilfield Rentals Limited
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Scotland |
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ProActive Compliance, L.L.C.
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Delaware |
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Production Management Industries, L.L.C.
|
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Louisiana |
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SE Finance LP
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Delaware |
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SEGEN LLC
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Delaware |
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SELIM LLC
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Delaware |
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SEMO, L.L.C.
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Louisiana |
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SEMSE, L.L.C.
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Louisiana |
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SES Canada, ULC
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Canada |
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STATE OF JURISDICTION OF |
NAME |
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INCORPORATION OR ORGANIZATION |
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SESI, L.L.C.
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Delaware |
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SPN Resources, LLC
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Louisiana |
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Southeast Australian Services Pty., Ltd.
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Australia |
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Stabil Drill Specialties, L.L.C.
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Louisiana |
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Stabil Drill (UK), Limited
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Scotland |
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Sub-Surface Tools, L.L.C.
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Louisiana |
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Superior Canada Holdings, Inc.
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Delaware |
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Superior Energy Liftboats, L.L.C.
|
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Louisiana |
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Superior Energy Services Limited
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Scotland |
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Superior Energy Services, L.L.C.
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Louisiana |
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Superior Energy Services de Mexico, S. de R.L. de C.V
|
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. Mexico |
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Superior Energy Staffing de Mexico, S. de R.L. de C.V
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. Mexico |
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Superior Energy Services de Venezuela, C.A.
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Venezuela |
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Superior Energy Services (Holdings), Limited
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Scotland |
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Superior Energy Services Trinidad Limited.
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Trinidad/Tobago |
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Superior Inspection Services, Inc.
|
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Louisiana |
|
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Universal Fishing and Rental Tools, Inc.
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Louisiana |
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Wild Well Control, Inc.
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Texas |
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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. 333-123442 on Form S-3 and
No. 333-12175, No. 333-43421, No. 333-33758,
No. 333-101211, No. 333-116078 and No. 333-125316 on Form S-8 of
Superior Energy Services, Inc. of our reports dated March 8, 2006, with respect to the consolidated
balance sheets of Superior Energy Services, Inc. and subsidiaries as of December 31, 2005 and 2004,
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, 2005, the related
consolidated financial statement schedule, managements assessment of the effectiveness of internal
control over financial reporting as of December 31, 2005, and the effectiveness of internal control
over financial reporting as of December 31, 2005, which reports appear in the December 31, 2005
annual report on Form 10-K of Superior Energy Services, Inc.
/s/ KPMG LLP
New Orleans, Louisiana
March 8, 2006
exv23w2
Exhibit 23.2
DeGolyer and MacNaughton
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244
March 10, 2006
Superior Energy Services, Inc.
1105 Peters Road
Harvey, LA 70058
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, 2005 on Certain Properties owned by SPN
Resources, LLC. (our Report) in the Annual Report on Form 10K of Superior Energy Services, Inc. for
the year ended in December 31, 2005, as well as in the Notes to the Consolidated Financial
Statements included therein. SPN Resources, LLC. is a wholly owned subsidiary of Superior Energy
Services, Inc. In addition, we hereby consent to the incorporation by reference of such
reference to DeGolyer and MacNaughton and to our Report in Superior Energy Services, Inc.s Registration
Statements on Form S-3 (Registration No. 333-123442 and No. 333-35286) and on Form S-8 (Registration Nos. 333-125316,
333-116078, 333-101211, 333-33758, 333-43421, and 333-12175).
|
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Very truly yours,
/s/ DeGOLYER and MacNAUGHTON
|
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|
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. |
|
I have reviewed this annual report on Form 10-K of Superior Energy Services, Inc.; |
|
2. |
|
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; |
|
|
b) |
|
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; |
|
|
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 |
|
|
d) |
|
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) |
|
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 |
|
|
b) |
|
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: March 10, 2006
|
|
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|
|
|
/s/ Terence E. Hall |
|
|
|
|
Terence E. Hall
|
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|
|
|
Chairman of the Board and Chief Executive Officer |
|
|
Superior Energy Services, Inc. |
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. |
|
I have reviewed this annual report on Form 10-K of Superior Energy Services, Inc.; |
|
2. |
|
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; |
|
|
b) |
|
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; |
|
|
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 |
|
|
d) |
|
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) |
|
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 |
|
|
b) |
|
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: March 10, 2006
|
|
|
|
|
|
|
/s/ Robert S. Taylor |
|
|
|
|
Robert S. Taylor
|
|
|
|
|
Executive Vice President, Treasurer and Chief Financial Officer |
|
|
Superior Energy Services, Inc. |
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, 2005 (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: March 10, 2006
|
|
|
|
|
|
|
|
|
/s/ Terence E. Hall
|
|
|
Terence E. Hall |
|
|
Chairman of the Board and Chief Executive 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.
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 quarterly period ended December 31,
2005 (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: March 10, 2006
|
|
|
|
|
|
|
|
|
/s/ Robert S. Taylor
|
|
|
Robert S. Taylor |
|
|
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.