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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM.........TO........
COMMISSION FILE NO. 0-20310
SUPERIOR ENERGY SERVICES, INC.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 75-2379388
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)
1105 PETERS ROAD
HARVEY, LA 70058
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
REGISTRANT'S TELEPHONE NUMBER: (504) 362-4321
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
Title of each class: Name of each exchange on which registered:
Common Stock, $.001 Par Value New York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
NONE
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
Indicate by check mark whether the Registrant is an accelerated filer (as
defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes [X] No [ ]
The aggregate market value of the voting stock held by non-affiliates of the
Registrant at June 30, 2003 based on the closing price on the New York Stock
Exchange on that date was $525,743,000.
The number of shares of the Registrant's common stock outstanding on March 1,
2004 was 74,218,201.
DOCUMENTS INCORPORATED BY REFERENCE
Certain information called for by Items 10, 11, 12, 13 and 14 of Part III will
be included in an amendment to this Form 10-K or incorporated by reference from
the Registrant's definitive proxy statement to be filed pursuant to Regulation
14A.
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SUPERIOR ENERGY SERVICES, INC.
ANNUAL REPORT ON FORM 10-K FOR
THE FISCAL YEAR ENDED DECEMBER 31, 2003
TABLE OF CONTENTS
Page
PART I
Items 1. & 2.Business and Properties 1
Item 3. Legal Proceedings 9
Item 4. Submission of Matters to a Vote of Security Holders 9
Item 4A. Executive Officers of Registrant 10
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters 11
Item 6. Selected Financial Data 12
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 13
Item 7A. Quantitative and Qualitative Disclosures about Market Risk 21
Item 8. Financial Statements and Supplementary Data 23
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 44
Item 9A. Controls and Procedures 44
PART III
Item 10. Directors and Executive Officers of the Registrant 45
Item 11. Executive Compensation 45
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters 45
Item 13. Certain Relationships and Related Transactions 45
Item 14. Principal Accountant Fees and Services 45
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K 46
(i)
PART I
ITEMS 1. & 2. BUSINESS AND PROPERTIES
GENERAL
We are a leading provider of specialized oilfield services and equipment focused
on serving the production-related needs of oil and gas companies in the Gulf of
Mexico. We believe that we are one of the few companies in the Gulf of Mexico
capable of providing most of the post wellhead products and services necessary
to maintain 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.
Over the past several years, we have significantly expanded the geographic scope
of our operations and the range of production-related services we provide
through both internal growth and strategic acquisitions. We have expanded our
geographic focus to select international market areas and added complementary
product and service offerings. Currently, we provide a full range of products
and services for our customers, including well intervention services, marine
services, rental tools and other oilfield services.
OPERATIONS
Well Intervention Services. We provide well intervention services that stimulate
oil and gas production using platforms or liftboats rather than through the use
of a drilling rig, which we believe provides a cost advantage to our customers.
These services include coiled tubing, electric wireline, mechanical wireline,
pumping and stimulation, artificial lift, well control, snubbing, recompletion,
engineering and well evaluation services. We are the leading provider of
mechanical wireline services in the Gulf of Mexico with approximately 180
offshore wireline units, 20 land wireline units and 11 dedicated liftboats
configured specifically for wireline services. We also perform both permanent
and temporary plug and abandonment services.
In 2003, we expanded our well intervention services to include acquiring mature,
shallow water oil and gas properties in the Gulf of Mexico to provide our
customers a cost-effective alternative to the decommissioning process. Once
properties are acquired, we will develop and produce the remaining reserves and
then plug and abandon the wells and decommission and abandon all well
facilities. Our goal is to provide additional opportunities for our well
intervention group and to expand our well intervention services from our
traditional emphasis on plugging and abandoning wells to facility salvaging and
decommissioning activities by using our liftboat fleet when possible. We hope to
achieve our goals in this area by efficiently developing acquired reserves and
performing decommissioning and abandonment work, lowering lease operating
expenses and adding new reserves through well work. The intent is to partially
offset the seasonal and cyclical nature of our business by scheduling work
during slower periods. In December 2003, we acquired our first offshore
properties, most of which are in water-depths accessible by our liftboat fleet.
Marine Services. We own and operate the largest and most diverse liftboat fleet
in the world. A liftboat is a self-propelled, self-elevating work platform with
legs, cranes and living accommodations. We believe that our liftboat fleet is
highly complementary to our well intervention services. Our fleet consists of 53
liftboats, including 11 liftboats configured specifically for wireline services
and 42 in our rental fleet with leg-lengths from 65 feet through 250 feet. All
but one of our liftboats are currently operating in the Gulf of Mexico and
represent approximately 24% of the liftboats located in the Gulf of Mexico. We
currently have a 200-foot class liftboat and under contract in Venezuela. We
intend to reposition some of our larger liftboats to international market areas
under long-term contracts as opportunities arise.
Rental Tools. We are a leading provider of rental tools in the Gulf of Mexico.
We manufacture, sell and rent specialized equipment for use with offshore and
onshore oil and gas well drilling, completion, production and workover
activities. Through internal growth and acquisitions, we have increased the size
and breadth of our rental tool inventory and now have 36 locations in all major
staging points for offshore oil and gas activities in the Gulf of Mexico. We
also have rental tool operations in Venezuela, Trinidad, Canada, the United
Kingdom, the Netherlands and the Middle East with a limited inventory of rental
tools for these market areas. Our rental tools include pressure
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control equipment, specialty tubular goods, connecting iron, handling tools,
drill pipe, bolting equipment, tongs, power swivels and stabilizers. We also
provide both land and offshore on-site accommodations through our rental tools
segment.
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 120 offshore facilities in the Gulf of Mexico. We also provide
non-hazardous oilfield waste management and environmental cleaning services,
including tank and vessel cleaning and safe vessel entry. We sell oil spill
containment inflatable boom and ancillary storage, deployment and retrieval
equipment. We also provide other services, including the manufacture and sale of
specialized drilling rig instrumentation, electronic torque and pressure control
equipment.
For additional industry segment financial information, see note 15 to our
consolidated financial statements.
CUSTOMERS
Our customers have primarily been the major and independent oil and gas
companies operating on the U.S. continental shelf. In 2003, 2002 and 2001, sales
to ChevronTexaco accounted for approximately 11%, 12% and 12% of our total
revenue, respectively, primarily in the well intervention and other oilfield
services segments. 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:
o changes in competitive prices,
o oil and gas prices and industry perceptions of future prices,
o fluctuations in the level of activity by oil and gas producers,
o changes in the number of liftboats operating in the Gulf of
Mexico,
o the ability of oil and gas producers to generate capital,
o general economic conditions and
o governmental regulation.
We compete with the oil and gas industry's 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 such 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 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.
Further, if our competitors construct additional liftboats for the Gulf of
Mexico market area, it will increase the competition for that service.
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
provider's reputation for safety and quality. Although we believe that our
reputation for safety and quality service is a key advantage, we cannot assure
that we will be able to maintain our competitive position.
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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, by focusing on the belief that
all safety and environmental incidents are preventable and an injury-free
workplace is achievable by creating a culture that emphasizes correct behavior.
We have introduced a company-wide effort to enhance a behavioral safety process
and training program that makes safety a constant focus of awareness through
open communication with all 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. Results from
this program were evident as our safety performance improved significantly in
2003.
POTENTIAL LIABILITIES AND INSURANCE
Our operations involve a high degree of operational risk, particularly of
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 at 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 with
industry standards and required by our customers. In addition, changes in the
insurance industry have generally led to higher insurance costs and decreased
availability of coverage. The availability of insurance covering risks we and
our competitors typically insure against may decrease, and the insurance that we
are able to obtain may have higher deductibles, higher premiums and more
restrictive policy terms.
GOVERNMENTAL REGULATION
Our business is significantly affected by the following:
o state and federal laws and other regulations relating to the oil
and gas industry,
o changes in such laws and regulations and
o 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. 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.
Federal and state laws require owners of non-producing wells to plug the well
and remove all exposed piping and rigging before the well is permanently
abandoned. The timing and need for plug and abandonment services for wells
situated on the U.S. continental shelf are regulated by the Minerals Management
Service (MMS) of the United States Department of the Interior. State regulatory
agencies similarly regulate plug and abandonment services within state coastal
waters.
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.
In addition, the demand for our services from the oil and gas industry is
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.
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.
Our operations also subject us to compliance with certain federal and state
pollution control and environmental protection laws and regulations. The
technical requirements of these laws and regulations are becoming increasingly
complex and stringent, and compliance is becoming increasingly difficult and
expensive. We believe
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that our present operations substantially comply with these laws and regulations
and that such compliance has had no material adverse effect upon our operations.
Sanctions for noncompliance may include the following:
o revocation of permits,
o corrective action orders,
o administrative or civil penalties and
o criminal prosecution.
The MMS requires holders of offshore oil and gas leases to post bonds in
connection with the plugging and abandonment of wells located offshore and the
removal of all production facilities. We currently have bonded our offshore
leases as required by the MMS, consisting of a $3.0 million Area-Wide Bond plus
a $300,000 Pipeline Right-of-Way Bond. Our leases contain standardized terms and
require compliance with detailed MMS regulations and orders. These MMS
directives are subject to change. The MMS has promulgated regulations requiring
offshore production facilities located on the U.S. continental shelf to meet
stringent engineering and construction specifications. The MMS has also
promulgated other regulations governing the plugging and abandonment of wells
located offshore and the removal of all production facilities. Finally, under
certain circumstances, the MMS may require any operations on federal leases to
be suspended or terminated.
Certain environmental laws provide for joint and several strict liabilities for
remediation of spills and other releases of hazardous substances. In addition,
companies may be subject to claims alleging personal injury or property damage
as a result of alleged exposure to hazardous substances. Finally, some
environmental statutes impose strict liability, which could render us liable for
environmental damage without regard to our negligence or fault. It is possible
that changes in environmental laws and enforcement policies, or claims for
damages to people, property, natural resources or the environment could result
in substantial costs and liabilities to us. 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.
EMPLOYEES
As of March 1, 2004, we had approximately 3,150 employees. None of our employees
is represented by a union or covered by a collective bargaining agreement. We
believe that our relationship with our employees is good.
FACILITIES
Our corporate headquarters are located on a 17-acre tract in Harvey, Louisiana.
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. We support the operations conducted by our
liftboats from a 3.5-acre maintenance and office facility in New Iberia,
Louisiana located on the Intracoastal Waterway that provides access to the Gulf
of Mexico. We also own certain facilities and lease other office, service and
assembly facilities under various operating leases. We have a total of 77
facilities located in Louisiana, Texas, Alabama, Oklahoma, Venezuela, Australia,
Trinidad, the United Kingdom, Canada, the Netherlands, and the Middle East 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.
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 web site 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 web site. The information posted on our web site is not incorporated into
this Annual Report.
4
CAUTIONARY STATEMENTS
Certain statements made in this Annual Report that are not historical facts are
"forward-looking statements." Such forward-looking statements may include,
without limitation, statements that relate to:
o our business strategy, plans and objectives,
o our beliefs and expectations regarding future demand for our
products and services and other events and conditions that may
influence the oilfield services market and our performance in the
future and
o our future expansion plans, including our anticipated level of
capital expenditures for, and the nature and scheduling of,
purchases or manufacture of rental tools, equipment and liftboats.
Also, you can generally identify forward-looking statements by such terminology
as "may," "will," "expect," "believe," "anticipate," "project," "estimate" or
similar expressions. Such statements are based on certain assumptions and
analyses made by our management in light of its experience and its perception of
historical trends, current conditions, expected future developments and other
factors it believes to be appropriate. We caution you that such statements are
only predictions and not guarantees of future performance and that actual
results, developments and business decisions may differ from those envisioned by
the forward-looking statements.
RISK FACTORS
All phases of our operations are subject to a number of uncertainties, risks and
other influences, many of which are beyond our control. Any one of such
influences, or a combination, could materially affect the accuracy of the
forward-looking statements and the projections on which the statements are
based. Some important factors that could cause actual results to differ
materially from the anticipated results or other expectations expressed in our
forward-looking statements include the following:
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:
o oil and gas prices and industry perceptions of future prices,
o the cost of exploring for, producing and delivering oil and gas,
o the ability of oil and gas companies to generate capital,
o the sale and expiration dates of offshore leases,
o the discovery rate of new oil and gas reserves and
o 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 and
results of operations.
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:
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o changes in competitive prices,
o fluctuations in the level of activity in major markets,
o an increased number of liftboats in the Gulf of Mexico,
o general economic conditions and
o governmental regulation.
We compete with the oil and gas industry's 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 provider's 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.
OUR OIL AND GAS OPERATIONS WILL INVOLVE SIGNIFICANT RISKS.
Any acquisitions of mature oil and gas properties will require an assessment of
a number of factors beyond our control. These factors include estimates of
recoverable reserves, future oil and gas prices, operating costs and potential
environmental and plugging and abandonment liabilities. These assessments,
especially estimates of oil and gas reserves, are inexact and their accuracy is
inherently uncertain. In connection with these assessments, we will perform a
review that we believe is generally consistent with industry practices. However,
our reviews will 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 or environmental problems that may exist or arise. In
connection with our acquisitions, we expect to acquire properties on an "as is"
basis and assume all plugging, abandonment and environmental liability with
limited remedies for breaches of representations and warranties. Therefore, the
risk is that we may overestimate the value of economically recoverable reserves
and underestimate the cost of plugging wells and abandoning production
facilities. Our oil and gas operations will also be subject to risks incident to
the operation of producing wells, including, but not limited to, uncontrollable
flows of oil, gas, brine or well fluids into the environment, blowouts,
cratering, mechanical difficulties, fires, explosions, pollution and other
risks, any of which could result in substantial losses to us.
WE ARE SUSCEPTIBLE TO ADVERSE WEATHER CONDITIONS IN THE GULF OF MEXICO.
Our operations are directly affected by the seasonal differences in weather
patterns in the Gulf of Mexico. These differences may result in increased
operations in the spring, summer and fall periods and a decrease in the winter
months. The seasonality of oil and gas industry activity as a whole in the Gulf
Coast region also affects our operations and sales of equipment. Weather
conditions generally result in higher drilling activity in the spring, summer
and fall months with the lowest activity in winter months. The rainy weather,
hurricanes and other storms prevalent in the Gulf of Mexico and along the Gulf
Coast throughout the year may also affect our operations. Accordingly, our
operating results may vary from quarter to quarter, depending on factors outside
of our control. As a result, full year results are not likely to be a direct
multiple of any particular quarter or combination of quarters.
WE DEPEND ON KEY PERSONNEL.
Our success depends to a great degree on the abilities of our key management
personnel, particularly our Chief Executive Officer and other high-ranking
executives. The loss of the services of one or more of these key employees could
adversely affect us.
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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. 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.
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:
o lack of sufficient executive-level personnel,
o increased administrative burden and
o increased logistical problems common to large,
expansive operations.
If we do not manage these potential difficulties successfully, our operating
results could be adversely affected. The historical financial information herein
is not necessarily indicative of the results that would have been achieved had
we been operated on a fully integrated basis or the results that may be realized
in the future.
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 DANGERS INHERENT IN OUR OPERATIONS AND THE LIMITS ON INSURANCE COVERAGE
COULD EXPOSE US TO POTENTIALLY SIGNIFICANT LIABILITY COSTS.
Our operations involve the use of liftboats, heavy equipment and exposure to
inherent risks, including equipment failure, blowouts, explosions and fire. In
addition, our liftboats are subject to operating risks such as catastrophic
marine disaster, adverse weather conditions, mechanical failure, collisions, oil
and hazardous substance spills and navigation errors. The occurrence of any of
these events could result in our liability for personal injury and property
damage, pollution or other environmental hazards, loss of production or loss of
equipment. 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 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 or
equipment 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 what we believe is prudent insurance
protection. However, we cannot guarantee that we will be able to maintain
adequate insurance in the future at rates we consider reasonable or that our
insurance coverage will be adequate to cover future claims that may arise.
Successful claims for which we are not fully insured may adversely affect our
working capital and profitability. In addition, changes in the
7
insurance industry have generally led to higher insurance costs and decreased
availability of coverage. The availability of insurance covering risks we and
our competitors typically insure against may decrease, and the insurance that we
are able to obtain may have higher deductibles, higher premiums and more
restrictive policy terms.
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.
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 and by changes in such laws and
the level of enforcement of such laws. 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.
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 also 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.
AS WE EXPAND OUR INTERNATIONAL OPERATIONS, WE WILL BE SUBJECT TO ADDITIONAL
POLITICAL, ECONOMIC AND OTHER UNCERTAINTIES.
A key element of our business strategy is to expand our operations into
international oil and gas producing areas. These international operations are
subject to a number of risks inherent in any business operating in foreign
countries including, but not limited to:
o political, social and economic instability,
o potential seizure or nationalization of assets,
o increased operating costs,
o modification or renegotiating of contracts,
o import-export quotas,
8
o currency fluctuations and
o other forms of government regulation which are beyond our
control.
Our operations have not yet been affected materially 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 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 assets. To the extent we make investments in
foreign assets 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:
o the awarding of contracts to local contractors,
o the employment of local citizens and
o 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.
OUR PRINCIPAL STOCKHOLDERS HAVE SUBSTANTIAL CONTROL.
Certain investment funds managed by First Reserve Corporation beneficially own
approximately 24% of our outstanding common stock. As a result, they exercise
substantial influence over the outcome of most matters requiring a stockholder
vote. In addition, pursuant to a stockholders' agreement, the First Reserve
funds are entitled to designate two directors to serve on the board. The First
Reserve funds will continue to be entitled to designate these directors until
the stockholders' agreement terminates on July 15, 2009 or in the event of
certain substantial reductions of their ownership interest.
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. A significant increase
in the wages paid by competing employers 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 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
9
ITEM 4A. EXECUTIVE OFFICERS OF REGISTRANT
The following table sets forth certain information about our executive officers.
Name and Age Position
------------ --------
Terence E. Hall, 58................... Chairman of the Board, Chief
Executive Officer and President
Kenneth L. Blanchard, 54.............. Chief Operating Officer and
Executive Vice President
Robert S. Taylor, 49.................. Chief Financial Officer, Vice
President and Treasurer
Terence E. Hall has served as our Chairman of the Board, Chief Executive
Officer, President and Director since December 1995.
Kenneth L. Blanchard has served as our Chief Operating Officer since June 2002
and as one of our Vice Presidents since December 1995.
Robert S. Taylor has served as our Chief Financial Officer since January 1996
and as one of our Vice Presidents since July 1999.
10
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Our common stock trades on the New York Stock Exchange under the symbol "SPN."
The following table sets forth the high and low sales prices per share of common
stock as reported for each fiscal quarter during the periods indicated.
HIGH LOW
2002
First Quarter $ 10.88 $ 7.88
Second Quarter 11.65 9.07
Third Quarter 10.10 5.95
Fourth Quarter 9.03 5.97
2003
First Quarter $ 9.80 $ 6.80
Second Quarter 11.65 8.30
Third Quarter 10.97 8.40
Fourth Quarter 10.25 8.27
2004
First Quarter (through March 1, 2004) $ 10.28 $ 8.98
As of March 1, 2004, there were 74,218,201 shares of Common Stock outstanding,
which were held by 122 record holders.
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.
We have four stock incentive plans to provide long-term incentives to our key
employees, including officers and directors, consultants and advisers. The
following table provides information about these incentive plans as of December
31, 2003:
Equity Compensation Plan Information
------------------------------------
Weighted- Number of Securities
Number of Securities Average Remaining Available
to be issued upon Exercise Price of for Future Issuance
Exercise of Outstanding under Equity
Plan Category Outstanding Options Options Compensation Plans
- -------------------------------------------------------------------------------------------------
Equity compensation Plans
Approved by Stockholders 5,628,000 $ 7.53 1,401,101(1)
Equity Compensation Plans Not
Approved by Stockholders - $ - 8,885(2)
(1) Of the shares remaining available for issuance under the Company's 1999
Stock Incentive Plan and 2002 Stock Incentive Plan, no more than
250,000 shares may be issued as restricted stock or "other stock-based
awards" (which awards are valued in whole or in part on the value of
the shares of Common Stock) under each plan. Of the shares remaining
for issuance under the Company's 1995 Stock Incentive Plan, there is no
limit to how many of the shares may be issued as restricted stock or
"other stock-based awards."
11
(2) Under our Director's Stock Plan, our non-employee directors may elect
to receive up to 100%, in 25% increments, of any fees paid by the
Company in common stock. The fees are converted into shares of common
stock in an amount equal to the director's compensation divided by the
average price of the stock for the calendar quarter in which the
election is made.
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, "Management's Discussion and Analysis of
Financial Condition and Results of Operation" and our consolidated financial
statements included elsewhere in this Annual Report. The financial data is in
thousands, except per share amounts.
Years Ended December 31,
--------------------------------------------------------------------------
2003 2002 2001 2000 1999
---- ---- ---- ---- ----
Revenues $500,625 $443,147 $449,042(1) $257,502(2) $113,076(3)
Income from operations 67,343 57,021 104,953 43,359 10,016
Income (loss) before cumulative
effect of change in accounting
principle 30,514 21,886 51,187 18,324(4) (6,548)(4)
Cumulative effect of change in
accounting principle, net - - 2,589(5) - -
Net income (loss) 30,514 21,886 53,776 18,324 (6,548)
Net income (loss) before
cumulative effect of change in
accounting principle per share:
Basic 0.41 0.30 0.74 0.28 (0.25)
Diluted 0.41 0.30 0.73 0.28 (0.25)
Net income (loss) per share:
Basic 0.41 0.30 0.78 0.28 (0.25)
Diluted 0.41 0.30 0.77 0.28 (0.25)
Total assets 832,863 727,620 665,520 430,676 282,255
Long-term debt, less current portion 255,516 256,334 269,633 146,393 117,459
Stockholders' equity 368,129 335,342 269,576 206,247 121,487
(1) 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
company's acquisition date.
(2) In the year ended December 31, 2000, we made six acquisitions for $42.5
million in initial aggregate cash consideration. These acquisitions have
been accounted for as purchases, and the results of operations have been
included from the respective company's acquisition date.
(3) On July 15, 1999, we acquired Cardinal through a stock for stock merger.
The merger was accounted for as a reverse acquisition, which resulted in
the adjustment of our net assets existing at the time of the merger to
their estimated fair value as required by the rules of purchase accounting.
Our operating results have been included from July 15, 1999. We made
another acquisition in November 1999 for approximately $2.9 million in cash
and 597,000 shares of our common stock that was accounted for as a
purchase, and the results of operations have been included from the
acquisition date.
12
(4) Income (loss) before cumulative effect of change in accounting principle
has been restated for 2000 and 1999 to include losses due to a refinance of
our indebtedness of $1.6 million (net of a $1.0 million income tax benefit)
and $4.5 million (net of a $2.1 million income tax benefit), respectively.
In accordance with Statement of Financial Accounting Standards No. 145 (FAS
No. 145), "Rescission of FASB Statements No. 4, 44 and 64, Amendment of
FASB Statement No. 13 and Technical Corrections," we have reclassified
these losses, as they are no longer considered extraordinary items.
(5) 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.
ITEM 7. MANAGEMENT'S 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. 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 "Cautionary Statements."
EXECUTIVE SUMMARY
We are a leading provider of specialized oilfield services and equipment focused
on serving the production-related needs of oil and gas companies primarily
operating in the Gulf of Mexico. We operate our businesses through four segments
- - well intervention, marine, rental tools and other oilfield services. Although
most of our revenue is derived from enhancing production from existing wells, a
significant portion of our revenue from our rental tool businesses are derived
from drilling-related activity.
We operate in highly competitive markets where revenue and earnings are driven
by competitive pricing, changes in the level of customer spending on drilling
and production-related projects, general economic conditions and governmental
regulations. Most of our work is on a call-out basis, meaning projects are
secured within days before commencing, and completed within a month. As a
result, predicting revenue and earnings is difficult because backlog, or
guaranteed future work, is not typical for the products and services we offer in
the markets we compete. We believe the key differentiating factors in our
industry are product and service quality; project management and coordination;
availability and reliability of assets and personnel; health, safety and
environmental standards; and price. Key business drivers include the Gulf of
Mexico drilling rig count, oil and natural gas production levels; current and
expected future energy prices, particularly natural gas prices; and customers'
capital spending allocated for Gulf of Mexico drilling and production.
In 2003, we experienced revenue growth in three of our four business segments as
compared to 2002. Revenue was a record $500.6 million and net income was $30.5
million, or $0.41 per share. Despite our record revenue, our core Gulf of Mexico
market area experienced only a modest upturn in activity in 2003 over 2002.
Although production-related activity slightly increased, the average number of
drilling rigs working offshore in the Gulf of Mexico was 108 in 2003, down from
an average of 113 rigs in 2002, further indicating that overall demand for
oilfield services did not meaningfully recover during the year.
Energy producers continue to deploy the cash flows they reaped from high
commodity prices to strengthen their balance sheets and improve their returns on
capital. Although energy producers have historically reinvested the vast
majority of their cash flows in further exploration and production
opportunities, they now seem to be cutting back on these expenditures. They also
seem to be reinvesting more of their cash flows into international opportunities
rather than in the Gulf of Mexico market area.
We believe the shallow water Gulf of Mexico still has economically viable
prospects, and much is being done to stimulate additional exploration and
production, such as royalty relief for deep drilling on the U.S. continental
shelf. We believe the Gulf of Mexico will see activity levels increase on a
long-term basis as properties change owners from major integrated producers to
independents, and as producers drill several deep water prospects. However,
13
while activity levels remain relatively low, we have implemented two strategies
to increase the utilization of our assets and enhance our earnings potential.
One of the strategies to enhance our financial performance is to acquire, manage
and decommission mature properties in the shallow waters of the Gulf of Mexico.
Our main objective in this new venture is to provide additional opportunities
for our other well intervention services, as well as our platform management
businesses. We will use our production-related services to enhance production
and, at the end of a property's economic life, use our assets to plug wells and
decommission properties. We will acquire older, more mature properties since
they need many of the production-enhancement services we provide. By owning the
properties, we can choose when we perform much of the work, helping to increase
the utilization of our assets and services during seasonal downtime. We made our
first acquisition of oil and gas properties in December 2003 and intend to
acquire other mature properties.
Our second strategy is to grow our international business. We intend to
accomplish this by seeking international expansion opportunities through both
internal growth and possible strategic acquisitions. We have identified other
markets that are similar to the Gulf of Mexico with many production-enhancement
opportunities. Those markets include Mexico, the Middle East, West Africa and
the North Sea, in addition to our locations in Australia, Eastern Canada,
Trinidad and Venezuela.
In August 2003, we increased our international business by acquiring Premier
Oilfield Services, a provider of rental tools based in Aberdeen, Scotland.
Premier Oilfield Services has operations in various rental markets such as the
North Sea, continental Europe, the Middle East and West Africa and will serve as
a gateway to provide our other rental tools and production-related services to
these markets.
We are also focusing on additional expansion within Mexico, Venezuela and
Trinidad since we believe they offer the best opportunity to deploy most of our
assets including liftboats, production-related services and rental tools. These
markets are close to our core Gulf of Mexico market and are forecasted to have
significant customer spending.
The discussion below gives a description of some of the drivers affecting the
performance of each segment and highlights some of the main factors that
impacted our performance in 2003. For additional industry segment financial
information, see note 15 to our consolidated financial statements.
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.
During 2003, we expanded our well intervention segment by forming a new
subsidiary, SPN Resources, LLC, to acquire, manage and decommission mature
properties in the shallow waters of the Gulf of Mexico. As previously mentioned,
the main objective of this new venture is to provide additional opportunities
for our other well intervention services, as well as our platform management
businesses. We intend to increase the utilization of our well intervention
services by deploying these services to our own properties during periods of
downtime. Since our first acquisition did not occur until December, this
expansion did not have a material financial impact on our 2003 operating
results.
Marine Segment
Liftboats have relatively high operating leverage, meaning that costs are fairly
fixed and, therefore, gross margins can change significantly from
quarter-to-quarter and year-to-year based on dayrates and utilization levels.
In 2003, it was difficult for us to maintain steady liftboat utilization due to
fluctuating customer demand and multiple weather disruptions in the Gulf of
Mexico. The average utilization of our liftboat fleet did not exceed 70% for any
quarter. Also, as the result of a tropical storm, one of our 200-foot class
liftboats sank in the Gulf of Mexico
14
on June 30, 2003. The vessel was declared a total loss, and we received $8
million of insurance proceeds for the vessel. We recorded a gain from the
insurance proceeds of $2.8 million.
Rental Tools Segment
Over time, our rental tools segment has shown consistent gross margin
percentages despite changing levels of industry demand. This has occurred
because many of their costs of services vary directly with revenue. In addition,
there tends to be little variation in pricing. As a result, changes in revenue
are primarily a function of utilization. The rental of drill pipe in the deep
water Gulf of Mexico is another factor driving the steady performance of this
segment. Drilling-related projects in the deep water Gulf of Mexico market area
typically last longer and are less impacted by changes in commodity prices and
other factors impacting drilling activity in the shallow water Gulf of Mexico.
Despite a small decline in the Gulf of Mexico rig count, our rental tools
revenue increased in 2003. This segment continued to expand internationally,
primarily in Eastern Canada and Trinidad. The acquisition of Premier Oilfield
Services, in Aberdeen, Scotland is serving to expand our rental tool operations
in the North Sea, continental Europe, the Middle East and West Africa.
Other Oilfield Services Segment
Demand for our dockside vessel and tank cleaning and non-hazardous waste
treatment businesses are primarily driven by drilling activity in the shallow
water Gulf of Mexico, as reflected by the drilling rig count. Much of the
cleaning and waste treatment is from residual waste created during the drilling
process. Our platform and field management businesses are highly competitive and
labor-intensive resulting in relatively low gross margins. Historically, the
field management business has contributed the largest percentage of revenue to
this segment, yielding gross margin percentages that have been lower than our
other segments.
The other oilfield services segment benefited from sales of oil spill
containment equipment early in 2003 as a result of a large oil spill off the
coast of Spain. However, the decline in drilling in the Gulf of Mexico
negatively impacted our environmental services, especially our non-hazardous
oilfield waste treatment business.
In August 2003, we sold our construction and fabrication assets. While this sale
has greatly reduced this segment's revenue, it has not had a material impact on
the segment's earnings because, historically, it was a business with low gross
margins.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Our discussion and analysis of our financial condition and results of operations
are based on our consolidated financial statements, which have been prepared in
accordance with accounting principles generally accepted in the United States.
The preparation of these financial statements requires us to make estimates and
assumptions that affect the amounts reported in our consolidated financial
statements and accompanying notes. Note 1 to our consolidated financial
statements contains a description of the accounting policies used in the
preparation of our financial statements. We evaluate our estimates on an ongoing
basis, including those related to long-lived assets and goodwill, income taxes,
allowance for doubtful accounts, self-insurance and oil and gas properties. We
base our estimates on historical experience and on various other assumptions
that we believe are reasonable under the circumstances. Actual amounts could
differ significantly from these estimates under different assumptions and
conditions.
We believe the following critical accounting policies are most important to the
presentation of our financial statements and require the most difficult,
subjective and complex judgments.
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
15
performance, 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 asset's 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. During the year ended December 31, 2003, we did not record
any impairment losses related to long-lived assets.
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 adopted Statement of
Financial Accounting Standards No. 142 (FAS No. 142), "Goodwill and Other
Intangible Assets," effective January 1, 2002. 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. We estimated 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 compared
these fair value estimates to the determined carrying value of our reporting
units. Based on this test, the fair value of the reporting units exceeded the
carrying amount, and no impairment loss has been 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.
Allowance for Doubtful Accounts. We maintain an allowance for doubtful accounts
for estimated losses resulting from the inability of our customers to make
required payments. These estimated allowances are periodically reviewed, on a
case by case basis, analyzing the customer's payment history and information
regarding customer's 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.
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. 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 excess insurance coverage, we cannot assure that such coverage
will adequately protect us against liability from all potential consequences.
16
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 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 then 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. At December 31, 2003, the balance of our oil and gas
properties was not significant at an estimated $5.5 million.
COMPARISON OF THE RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2003
AND 2002
For the year ended December 31, 2003, our revenues were $500.6 million resulting
in net income of $30.5 million or $0.41 diluted earnings per share. For the year
ended December 31, 2002, our revenues were $443.1 million and our net income was
$21.9 million or $0.30 diluted earnings per share. Our increase in revenue and
net income is the result of an overall increased demand for most of our services
due to increased activity by our customers. The following discussion analyzes
our operating results on a segment basis.
WELL INTERVENTION SEGMENT
Revenue for our well intervention segment was $188.0 million for the year ended
December 31, 2003, as compared to $148.7 million for 2002. This segment's gross
margin percentage increased slightly to 41% in the year ended December 31, 2003
from 37% in 2002. The increase in revenue and gross margin percentage is the
result of increased demand for almost all of our services as production-related
activity in the Gulf of Mexico increased. Our pumping and stimulation services
benefited the most from the increased activity levels in the Gulf of Mexico
while our hydraulic workover and well control services benefited from
international activity.
MARINE SEGMENT
Our marine revenue for the year ended December 31, 2003 increased 4% over 2002
to $70.4 million. The fleet's average dayrate increased to approximately $6,300
in the year ended December 31, 2003 from approximately $5,850 in 2002, and the
average utilization decreased to 66% for 2003 from 69% in 2002. The gross margin
percentage for the year ended December 31, 2003 decreased to 29% from 34% in
2002. While revenues and the average dayrate increased because of additions of
three larger liftboats to the fleet during 2002, a drop-off in utilization and
the increased costs of the new liftboats resulted in a lower gross margin
percentage. Increased costs, including maintenance and insurance, also
contributed to the decline in gross margin percentage.
RENTAL TOOLS SEGMENT
Revenue for our rental tools segment for the year ended December 31, 2003 was
$141.4 million, a 14% increase over 2002. The increase in this segment's revenue
was primarily due to an increased demand for our expanded inventory of rental
tool equipment and our geographic expansion. During 2003, revenue from
international markets grew as we continue to diversify outside of the Gulf of
Mexico market area. We acquired Premier Oilfield Services, an Aberdeen,
Scotland-based provider of oilfield equipment rentals, in August 2003 to further
this diversification. The gross margin percentage decreased slightly to 67% in
2003 from 69% in 2002 due primarily to a change in the mix of the demand for our
rental tools.
17
OTHER OILFIELD SERVICES SEGMENT
Other oilfield services revenue for the year ended December 31, 2003 was $100.9
million, a 2% decrease over the $102.5 million in revenue in 2002. The gross
margin percentage decreased slightly to 19% in 2003 from 20% in 2002. The lower
revenue is attributable to a decrease in construction and fabrication revenue as
the result of the sale of those assets in August 2003, which was partially
offset by increases in revenue from our field management services, growth in our
oilfield waste treatment business and higher sales of oil spill containment
equipment. This segment's slightly lower gross margin percentage was due to
additional costs associated with the sale of our construction and fabrication
assets and the growth and expansion of our oilfield waste treatment business,
which were partially offset by the increased sales of higher margin oil spill
containment equipment.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased to $48.9 million in the year ended
December 31, 2003 from $41.6 million in 2002. The increase resulted mostly from
our larger asset base as a result of our capital expenditures during 2002 and
2003.
GENERAL AND ADMINISTRATIVE
General and administrative expenses increased to $94.8 million for the year
ended December 31, 2003 from $86.2 million in 2002. The increase is primarily
the result of our internal growth and the acquisition of Premier Oilfield
Services. However, general and administrative expenses as a percentage of
revenue remained relatively unchanged at approximately 19% for both periods.
COMPARISON OF THE RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2002
AND 2001
For the year ended December 31, 2002, our revenues were $443.1 million resulting
in net income of $21.9 million or $0.30 diluted earnings per share, as compared
to revenue of $449.0 million and income before cumulative effect of change in
accounting principle of $51.2 million or $0.73 diluted earnings per share for
2001. The decrease in revenue and operating income is a result of reduced
activity by our customers, resulting in lower utilization of the Company's
expanded asset base. In 2002, we significantly expanded our capacity to serve
our customers by adding three large liftboats, expanding our rental tool
inventory, and expanding and enhancing several of our operating facilities. The
following discussion analyzes our operating results on a segment basis.
WELL INTERVENTION SEGMENT
Revenue for our well intervention segment was $148.7 million for the year ended
December 31, 2002, 13% lower than the same period in 2001. This segment's gross
margin decreased to 37% in the year ended December 31, 2002 from 44% in the year
ended December 31, 2001. Demand and pricing decreased for almost all of our
services as production-related activity decreased significantly.
MARINE SEGMENT
Our marine revenue for the year ended December 31, 2002 decreased 5% over the
same period in 2001 to $67.9 million. The gross margin percentage decreased to
34% from 52% as utilization for most liftboat classes declined in 2002 to 69%
from 78% in 2001. We added two 245-foot class liftboats and one 250-foot class
liftboat to our fleet during 2002. Although these larger liftboats earn higher
average dayrates, the fleet's average dayrate remained relatively unchanged from
2001.
RENTAL TOOLS SEGMENT
Revenue for our rental tools segment for the year ended December 31, 2002 was
$124.1 million, a 2% increase over the same period in 2001, and the rental tools
gross margin percentage increased to 69% from 66% in 2001. These increases
resulted from our acquisition of a drill pipe and handling tool rental company
near the end of the third quarter of 2001 and our larger asset base as a result
of our acquisitions and capital expenditures during 2001 and 2002.
18
OTHER OILFIELD SERVICES SEGMENT
Other oilfield services revenue for the year ended December 31, 2002 was $102.5
million, a 21% increase over the same period in 2001. The gross margin increased
slightly to $20.7 million in the year ended December 31, 2002 from $18.3 million
in the same period in 2001. This segment generated higher revenue and gross
margin primarily from the acquisition of an environmental services company in
January 2002.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization increased to $41.6 million in the year ended
December 31, 2002 from $33.4 million in 2001. The increase mostly resulted from
our larger asset base as a result of our acquisitions and capital expenditures
during 2001 and 2002. As of January 1, 2002, we ceased amortizing our goodwill,
while approximately $4.4 million of goodwill amortization expense was recorded
in the year ended December 31, 2001.
GENERAL AND ADMINISTRATIVE
General and administrative expenses increased to $86.2 million in the year ended
December 31, 2002 from $73.3 million in 2001. The increase is primarily the
result of our 2001 and 2002 acquisitions.
LIQUIDITY AND CAPITAL RESOURCES
In the year ended December 31, 2003, we generated net cash from operating
activities of $100.2 million. 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 $19.8 million at
December 31, 2003 compared to $3.5 million at December 31, 2002.
We made $50.2 million of capital expenditures during the year ended December 31,
2003, of which approximately $29.1 million was used to expand and maintain our
rental tool equipment inventory, approximately $8.8 million was used on
facilities construction (including our facility in Broussard, Louisiana) and
approximately $1.9 million was made in our marine segment. We also made $10.4
million of capital expenditures to expand and maintain the asset base of our
well intervention group and other oilfield services group.
In August 2003, we acquired Premier Oilfield Services, an Aberdeen,
Scotland-based provider of oilfield equipment rentals, in order to
geographically expand our operations and the rental tools segment. We paid $3.4
million in cash consideration for Premier Oilfield Services, including
transaction costs, and paid an additional $29.0 million to repay its existing
debt, concurrently with the acquisition.
We have outstanding $200 million of 8 7/8% senior notes due 2011. The indenture
governing the senior notes requires semi-annual interest payments, which
commenced November 15, 2001 and continue through the maturity date of May 15,
2011. 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 $147 million at December 31, 2003. The indenture also contains
covenants that restrict our ability to create certain liens, sell assets or
enter into certain mergers or acquisitions.
We also have a bank credit facility, which was amended in August 2003. The
amendment increased the balance of the term loans by $23 million to finance the
acquisition of Premier Oilfield Services and extended the maturity date of the
facility. At December 31, 2003, we had term loans in an aggregate amount of
$50.7 million outstanding and a revolving credit facility of $75 million, none
of which was outstanding. As of March 1, 2004, these balances were unchanged and
the weighted average interest rate on amounts outstanding under the credit
facility was 3.5% per annum. Indebtedness under the credit facility is secured
by substantially all of our assets, including the pledge of the stock of our
principal subsidiaries. The credit facility contains customary events of default
and requires that we
19
satisfy various financial covenants. It also limits our capital expenditures,
our ability to pay dividends or make other distributions, make acquisitions,
make changes to our capital structure, create liens or incur additional
indebtedness.
We have $19.0 million outstanding at December 31, 2003 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, which began
December 3, 2002, and matures on June 3, 2027. Our obligations are secured by
mortgages on the two liftboats. In accordance with the agreement, we are
required to comply with certain covenants and restrictions, including the
maintenance of minimum net worth and debt-to-equity requirements.
The following table summarizes our contractual cash obligations and commercial
commitments at December 31, 2003 (amounts in thousands) for our long-term debt
and operating leases. We do not have any other material obligations or
commitments.
Description 2004 2005 2006 2007 2008 Thereafter
- ----------- ---- ---- ---- ---- ---- ----------
Long-term debt $ 14,210 $ 20,610 $ 7,810 $ 7,810 $ 4,310 $ 214,976
Operating leases 4,275 2,796 1,879 1,359 641 12,423
------------------------------------------------------------------------------
Total $ 18,485 $ 23,406 $ 9,689 $ 9,169 $ 4,951 $ 227,399
==============================================================================
We have no off-balance sheet arrangements other than our guarantee of the Lamb
Energy Services credit facility (consisting of a $9 million term loan at
December 31, 2003 and a $3 million revolving credit facility, $500,000 of which
was outstanding as of December 31, 2003) and potential additional consideration
that may be payable as a result of our acquisitions. Additional consideration is
generally based on the acquired company's operating performance after the
acquisition as measured by earnings before interest, income taxes, depreciation
and amortization (EBITDA) and other adjustments intended to exclude
extraordinary items. While the amounts of additional consideration payable
depend upon the acquired company's operating performance and are difficult to
predict accurately, as of December 31, 2003, the maximum additional
consideration payable for the Company's remaining acquisitions will be
approximately $16.1 million, which will be determined in the second quarter of
2004 and payable during the second half of 2004. 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. We do not have any other financing arrangements that are not
required under generally accepted accounting principles to be reflected in our
financial statements. When amounts are determined, they are capitalized as part
of the purchase price of the related acquisition. In the year ended December 31,
2003, we capitalized additional consideration of $22.7 million related to five
of our acquisitions, of which $11.5 million was paid during 2003 and $11.2
million is expected to be paid in the first half of 2004.
We have identified capital expenditure projects that will require up to $50
million in 2004, exclusive of any acquisitions. 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 require additional
equity or debt financing in excess of our current working capital and amounts
available under our revolving credit facility.
NEW ACCOUNTING PRONOUNCEMENTS
In January 2003, the Financial Accounting Standards Board issued FASB
Interpretation No. 46 (FIN 46), "Consolidation of Variable Interest Entities."
FIN 46 clarifies the application of Accounting Research Bulletin Number 51,
"Consolidated Financial Statements," to certain entities in which equity
investors do not have the
20
characteristics of a controlling financial interest or do not have sufficient
equity at risk for the entity to finance its activities without additional
subordinated financial support from other parties. In December 2003, the
Financial Accounting Standards Board issued modifications to FIN 46 (FIN 46R),
resulting in multiple effective dates based on the nature as well as the
creation date of a Variable Interest Entity. We do not expect the adoption of
FIN 46 or FIN 46R to have a significant effect on our financial position or
results of operations.
In April 2003, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 149 (FAS No. 149), "Amendment of Statement
133 on Derivative Instruments and Hedging Activities." FAS No. 149 amends and
clarifies financial accounting and reporting for derivative instruments,
including certain derivative instruments embedded in other contracts
(collectively referred to as derivatives) and for hedging activities under
Statement of Financial Accounting Standards No. 133 (FAS No. 133), "Accounting
for Derivative Instruments and Hedging Activities." FAS No. 149 is effective for
contracts entered into or modified after September 30, 2003. The adoption of FAS
No. 149 did not have a significant effect on our financial position or results
of operations.
In May 2003, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 150 (FAS No. 150), "Accounting for Certain
Financial Instruments with Characteristics of Both Liabilities and Equity." FAS
No. 150 establishes standards for the classification and measurement of certain
financial instruments with characteristics of both liabilities and equity. FAS
No. 150 is effective for financial instruments entered into or modified after
May 31, 2003. The adoption of FAS No. 150 did not have a significant effect on
our financial position or results of operations. In July 2001, the Financial
Accounting Standards Board issued Statement of Financial Accounting Standards
No. 143 (FAS No. 143), "Accounting for Asset Retirement Obligations." This
standard requires us to record the fair value of a liability for an asset
retirement obligation in the period in which it is incurred and a corresponding
increase in the carrying amount of the related long-lived asset. FAS No. 143 is
effective for fiscal years beginning after June 15, 2002. The transition
adjustment resulting from the adoption of this statement will be reported as a
cumulative effect of change in accounting principle. We do not believe the
implementation of FAS No. 143 will have a significant impact on our financial
condition and results of operations.
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. The Company continually monitors 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 make limited 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 leveraged or complex features.
Derivative instruments are traded with creditworthy major financial
institutions. 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
On occasion, we use interest rate swap agreements to manage our interest rate
exposure. Under interest rate swap agreements, we agree with other parties to
exchange, at specific intervals, the difference between fixed-rate and
variable-rate interest amounts calculated by reference to an agreed-upon
notional principal amount. At December 31, 2001, we were party to an interest
rate swap with an approximate notional amount of $1.8 million designed to
21
convert a similar amount of variable-rate debt to fixed rates. The interest rate
was 5.675%, and the swap matured in October 2002.
At December 31, 2003, $50.7 million of our long-term debt had variable interest
rates. Based on debt outstanding at December 31, 2003, a 10% increase in
variable interest rates would increase our interest expense in the year 2003 by
approximately $178,000, while a 10% decrease would decrease our interest expense
by approximately $178,000.
22
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Independent Auditors' Report
The Board of Directors and Stockholders
Superior Energy Services, Inc.:
We have audited the consolidated balance sheets of Superior Energy Services,
Inc. and subsidiaries as of December 31, 2003 and 2002, 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, 2003. 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, 2003, 2002 and 2001. These
consolidated financial statements and financial statement schedule are the
responsibility of the Company's 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 auditing standards generally accepted
in the United States of America. 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, 2003 and 2002, and the
results of their operations and their cash flows for each of the years in the
three year period ended December 31, 2003, in conformity with accounting
principles generally accepted in the United States of America. Also, in our
opinion the related financial statement schedule, when considered in relation to
the basic consolidated financial statements taken as a whole, presents fairly,
in all material respects, the information set forth therein.
As discussed in Note 2 to the consolidated financial statements, the Company
changed its method of depreciation on its liftboat fleet in 2001.
As discussed in Note 1 to the consolidated financial statements, effective July
1, 2001, the Company adopted the provisions of Statement of Financial Accounting
Standards (SFAS) No. 141, "Business Combinations", and certain provisions of
SFAS No. 142, "Goodwill and Other Intangible Assets" as required for goodwill
and intangible assets resulting from business combinations initiated after June
30, 2001. On January 1, 2002, the Company adopted the remaining provisions of
SFAS No. 142.
KPMG LLP
New Orleans, Louisiana
March 4, 2004
23
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
December 31, 2003 and 2002
(in thousands, except share data)
2003 2002
---- ----
ASSETS
Current assets:
Cash and cash equivalents $ 19,794 $ 3,480
Accounts receivable - net of allowance for doubtful
accounts of $6,280 in 2003 and $4,617 in 2002 112,775 108,352
Income taxes receivable - 6,087
Current portion of notes receivable 19,212 -
Prepaid insurance and other 14,059 11,663
------------- -------------
Total current assets 165,840 129,582
------------- -------------
Property, plant and equipment - net 427,360 418,047
Goodwill - net 204,727 160,366
Notes receivable 15,145 -
Investments in affiliates 13,224 12,343
Other assets - net 6,567 7,282
------------- -------------
Total assets $ 832,863 $ 727,620
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 20,817 $ 21,010
Accrued expenses 48,949 33,871
Income taxes payable 138 -
Current portion of decommissioning liabilities 20,097 -
Current maturities of long-term debt 14,210 13,730
------------- -------------
Total current liabilities 104,211 68,611
------------- -------------
Deferred income taxes 86,251 67,333
Decommissioning liabilities 18,756 -
Long-term debt 255,516 256,334
Stockholders' equity:
Preferred stock of $.01 par value. Authorized,
5,000,000 shares; none issued - -
Common stock of $.001 par value. Authorized, 125,000,000
shares; issued and outstanding 74,099,081 and 73,819,341
at December 31, 2003 and 2002, respectively 74 74
Additional paid-in capital 370,798 368,746
Accumulated other comprehensive income 264 43
Accumulated deficit (3,007) (33,521)
------------- -------------
Total stockholders' equity 368,129 335,342
------------- -------------
Total liabilities and stockholders' equity $ 832,863 $ 727,620
============= =============
See accompanying notes to consolidated financial statements.
24
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Operations
Years Ended December 31, 2003, 2002 and 2001
(in thousands, except per share data)
2003 2002 2001
---- ---- ----
Revenues $ 500,625 $ 443,147 $ 449,042
------------- ------------- -------------
Costs and expenses:
Cost of services 289,607 258,334 237,355
Depreciation and amortization 48,853 41,595 33,446
General and administrative 94,822 86,197 73,288
------------- ------------- -------------
Total costs and expenses 433,282 386,126 344,089
------------- ------------- -------------
Income from operations 67,343 57,021 104,953
Other income (expense):
Interest expense, net of amounts capitalized (22,477) (21,884) (20,087)
Interest income 209 530 1,892
Other income 2,762 - -
Equity in earnings (loss) of affiliates 985 (80) -
------------- ------------- -------------
Income before income taxes and cumulative effect of
change in accounting principle 48,822 35,587 86,758
Income taxes 18,308 13,701 35,571
------------- ------------- -------------
Income before cumulative effect of change in
accounting principle $ 30,514 $ 21,886 $ 51,187
Cumulative effect of change in accounting principle,
net of income tax expense of $1,655 - - 2,589
------------- ------------- -------------
Net income $ 30,514 $ 21,886 $ 53,776
============= ============= =============
Basic earnings per share:
Earnings before cumulative effect of change in
accounting principle $ 0.41 $ 0.30 $ 0.74
Cumulative effect of change in accounting principle - - 0.04
------------- ------------- -------------
Earnings per share $ 0.41 $ 0.30 $ 0.78
============= ============= =============
Diluted earnings per share:
Earnings before cumulative effect of change in
accounting principle $ 0.41 $ 0.30 $ 0.73
Cumulative effect of change in accounting principle - - 0.04
------------- ------------- -------------
Earnings per share $ 0.41 $ 0.30 $ 0.77
============= ============= =============
Weighted average common shares used in computing earnings per share:
Basic 73,970 72,912 68,545
Incremental common shares from stock options 678 960 1,047
------------- ------------- -------------
Diluted 74,648 73,872 69,592
============= ============= =============
See accompanying notes to consolidated financial statements.
25
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Changes in Stockholders' Equity
Years Ended December 31, 2003, 2002 and 2001
(in thousands, except share data)
Accumulated
Preferred Common Additional other
stock Preferred stock Common paid-in comprehensive
shares stock shares stock capital income (loss)
-----------------------------------------------------------------------------------
Balances, December 31, 2000 - $ - 67,803,304 $ 68 $ 315,304 $ 58
Comprehensive income:
Net income - - - - - -
Other comprehensive loss -
Foreign currency translation
adjustment - - - - - (24)
Unrealized loss on derivatives - - - - - (18)
-----------------------------------------------------------------------------------
Total comprehensive income (loss) - - - - - (42)
Stock issued for acquisitions - - 825,612 1 6,217 -
Exercise of stock options and
related tax benefit, net - - 693,970 - 3,377 -
-----------------------------------------------------------------------------------
Balances, December 31, 2001 - - 69,322,886 69 324,898 16
Comprehensive income:
Net income - - - - - -
Other comprehensive income -
Foreign currency translation
adjustment - - - - - 9
Unrealized gain on derivatives - - - - - 18
-----------------------------------------------------------------------------------
Total comprehensive income - - - - - 27
Stock issued for cash - - 4,197,500 4 38,832 -
Exercise of stock options and
related tax benefit, net - - 298,955 1 5,016 -
-----------------------------------------------------------------------------------
Balances, December 31, 2002 - - 73,819,341 74 368,746 43
Comprehensive income:
Net income - - - - - -
Other comprehensive income -
Foreign currency translation
adjustment - - - - - 221
-----------------------------------------------------------------------------------
Total comprehensive income - - - - - 221
Exercise of stock options and
related tax benefit, net - - 279,740 - 2,052 -
-----------------------------------------------------------------------------------
Balances, December 31, 2003 - $ - 74,099,081 $ 74 $ 370,798 $ 264
===================================================================================
Accumulated
deficit Total
---------------------------
Balances, December 31, 2000 $ (109,183) $ 206,247
Comprehensive income:
Net income 53,776 53,776
Other comprehensive loss -
Foreign currency translation
adjustment - (24)
Unrealized loss on derivatives - (18)
---------------------------
Total comprehensive income (loss) 53,776 53,734
Stock issued for acquisitions - 6,218
Exercise of stock options and
related tax benefit, net - 3,377
---------------------------
Balances, December 31, 2001 (55,407) 269,576
Comprehensive income:
Net income 21,886 21,886
Other comprehensive income -
Foreign currency translation
adjustment - 9
Unrealized gain on derivatives - 18
---------------------------
Total comprehensive income 21,886 21,913
Stock issued for cash - 38,836
Exercise of stock options and
related tax benefit, net - 5,017
---------------------------
Balances, December 31, 2002 (33,521) 335,342
Comprehensive income:
Net income 30,514 30,514
Other comprehensive income -
Foreign currency translation
adjustment - 221
---------------------------
Total comprehensive income 30,514 30,735
Exercise of stock options and
related tax benefit, net - 2,052
---------------------------
Balances, December 31, 2003 $ (3,007) $ 368,129
===========================
See accompanying notes to consolidated financial statements.
26
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Years Ended December 31, 2003, 2002, and 2001
(in thousands)
2003 2002 2001
---- ---- ----
Cash flows from operating activities:
Net income $ 30,514 $ 21,886 $ 53,776
Adjustments to reconcile net income
to net cash provided by operating activities:
Depreciation and amortization 48,853 41,595 33,446
Deferred income taxes 15,183 17,669 25,865
Equity in (earnings) loss of affiliates (985) 80 -
Other income (2,762) - -
Amortization of debt acquisition costs 1,026 1,031 1,269
Cumulative effect of change in accounting principle - - (2,589)
Changes in operating assets and liabilities,
net of acquisitions:
Accounts receivable 104 4,629 (22,248)
Other - net 1,773 2,467 (462)
Accounts payable (1,932) (1,660) (6,816)
Accrued expenses 2,561 (7,466) 18,764
Income taxes 5,905 7,052 (11,656)
------------ ------------ ------------
Net cash provided by operating activities 100,240 87,283 89,349
------------ ------------ ------------
Cash flows from investing activities:
Payments for purchases of property and equipment (50,175) (104,452) (83,863)
Acquisitions of businesses, net of cash acquired (14,298) (7,653) (104,999)
Cash proceeds from insurance settlement 8,000 - -
Cash proceeds from asset disposition 313 - -
Increase in notes receivable - - (3,849)
Other - - 1,415
------------ ------------ ------------
Net cash used in investing activities (56,160) (112,105) (191,296)
------------ ------------ ------------
Cash flows from financing activities:
Net borrowings (payments) on revolving credit facility (9,250) 1,550 (8,800)
Proceeds from long-term debt 23,000 20,241 232,000
Principal payments on long-term debt (43,089) (39,582) (118,345)
Payment of debt acquisition costs (479) (1,529) (6,770)
Proceeds from exercise of stock options 2,052 5,017 3,377
Proceeds from issuance of stock - 38,836 -
------------ ------------ ------------
Net cash provided by (used in) financing activities (27,766) 24,533 101,462
------------ ------------ ------------
Net increase (decrease) in cash and cash equivalents 16,314 (289) (485)
Cash and cash equivalents at beginning of year 3,480 3,769 4,254
------------ ------------ ------------
Cash and cash equivalents at end of year $ 19,794 $ 3,480 $ 3,769
============ ============ ============
See accompanying notes to consolidated financial statements.
27
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2003, 2002, and 2001
(1) Summary of Significant Accounting Policies
(a) Basis of Presentation
The consolidated financial statements include the accounts of the
Company. All significant intercompany accounts and transactions are
eliminated in consolidation. Certain previously reported amounts have
been reclassified to conform to the 2003 presentation.
(b) Business
The Company is a leading provider of specialized oilfield services and
equipment focusing primarily on serving the production-related needs of
oil and gas companies in the Gulf of Mexico. The Company provides most
of the post wellhead products and services necessary to maintain
offshore producing wells, as well as plug and abandonment services at
the end of their life cycle. In recent years, the Company has expanded
its geographic focus to include serving the production-related needs of
oil and gas companies in select international market areas.
In December 2003, the Company acquired oil and gas properties in order
to provide additional opportunities for our well intervention and
platform management businesses 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.
The Company does not intend to risk any capital by participating in
exploratory drilling activities.
A majority of the Company's business is conducted with major and
independent oil and gas exploration companies. The Company continually
evaluates the financial strength of its customers but does not require
collateral to support the customer receivables.
The Company's well intervention and marine services segments are
contracted for specific projects on either a day rate or turnkey basis.
Rental tools are leased to customers on an as-needed basis on a day
rate basis. The Company derives a significant amount of its revenue
from a small number of major and independent oil and gas companies. In
2003, 2002 and 2001, one customer accounted for approximately 11%, 12%
and 12% of the Company's total revenue, respectively, primarily in the
well intervention and other oilfield services segments. The inability
of the Company to continue to perform services for a number of its
large existing customers, if not offset by sales to new or existing
customers, could have a material adverse effect on the Company's
business and financial condition.
(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) Cash Equivalents
The Company considers all short-term deposits with a maturity of ninety
days or less to be cash equivalents.
28
(e) Property, Plant and Equipment
Property, plant and equipment are stated at cost. Most of our
depreciation is computed using the straight-line method over the
estimated useful lives of the related assets as follows:
Buildings and improvements 15 to 30 years
Marine vessels and equipment 5 to 25 years
Machinery and equipment 5 to 15 years
Automobiles, trucks,
tractors and trailers 2 to 5 years
Furniture and fixtures 3 to 7 years
Marine vessels and oil and gas producing assets are depreciated or
depleted based on utilization or units of production, subject to a
minimum amount, because depreciation and depletion occur primarily
through use rather than through elapsed time.
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 2003, 2002 and
2001, the Company capitalized approximately $87,000, $1,066,000 and
$839,000, respectively, of interest for various capital expansion
projects.
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 asset. 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 asset exceeds its fair value. Assets to be
disposed of are reported at the lower of the carrying amount or fair
value less costs to sell.
The Company's subsidiary, SPN Resources, LLC acquires oil and natural
gas properties and assumes the related well abandonment and
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 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 unit of production basis based on the
estimated remaining equivalent proved oil and gas reserves of each
field. Well costs are depleted on a unit of production basis based on
the estimated remaining equivalent proved producing oil and gas
reserves of each field. Properties are assessed for impairment in
value, with any impairment charged to expense, whenever indicators
become evident.
(f) Goodwill
The Company adopted Statement of Financial Accounting Standards No. 142
(FAS No. 142), "Goodwill and Other Intangible Assets," effective
January 1, 2002. 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. In conjunction with the
adoption of Financial Accounting Standards No. 141 (FAS No. 141),
"Business Combinations," goodwill was no longer amortized for any
business combinations initiated or completed after June 30, 2001. In
connection with FAS No. 142, the transitional goodwill impairment
evaluation required the Company to perform an assessment of whether
there was an indication that goodwill was impaired as of the date of
adoption. To accomplish this, the Company identified its reporting
units (which are consistent with the Company's reportable segments) and
determined the carrying value of each reporting unit by assigning the
assets and liabilities, including the existing goodwill and intangible
assets, to those reporting units as of the date of adoption. The
Company then estimated the fair value of each reporting unit and
compared it to the reporting unit's carrying value.
29
Based on this test, the fair value of the reporting units exceeded the
carrying amount, and the second step of the impairment test was not
required. No impairment loss was recognized as the result of the
adoption of FAS No. 142 or in the years ended December 31, 2003 or
2002.
Prior to the adoption of FAS No. 142, the Company amortized goodwill
using the straight-line method over a period not to exceed 30 years,
and evaluated the recoverability of goodwill based on undiscounted
estimates for cash flows in accordance with Statement of Financial
Accounting Standards No. 121 (FAS No. 121), "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be
Disposed Of." Accumulated amortization of goodwill is $9,151,000 at
December 31, 2003 and 2002.
The following table presents net income for each period exclusive of
amortization expense recognized in such periods related to goodwill,
which is no longer amortized as a result of the adoption of FAS No.
142. Amounts are in thousands except per share information:
Year Ended
December 31,
-----------------------------------------
2003 2002 2001
------------ ----------- -----------
Income before cumulative effect of change
in accounting principle, as reported $ 30,514 $ 21,886 $ 51,187
Cumulative effect of change in accounting
principle, net of income tax expense, as reported - - 2,589
Goodwill amortization, net of income tax expense - - 4,172
----------- ---------- ----------
Net income, as adjusted $30,514 $21,886 $57,948
=========== ========== ==========
Basic earnings per share:
Earnings before cumulative effect of change
in accounting principle, as reported $ 0.41 $ 0.30 $ 0.74
Cumulative effect of change in accounting principle,
as reported - - 0.04
Goodwill amortization, net of income tax expense - - 0.06
----------- ---------- ----------
Earnings per share, as adjusted $ 0.41 $ 0.30 $ 0.84
=========== ========== ==========
Diluted earnings per share:
Earnings before cumulative effect of change
in accounting principle, as reported $ 0.41 $ 0.30 $ 0.73
Cumulative effect of change in accounting principle,
as reported - - 0.04
Goodwill amortization, net of income tax expense - - 0.06
----------- ---------- ----------
Earnings per share, as adjusted $ 0.41 $ 0.30 $ 0.83
=========== ========== ==========
Weighted average common shares used in computing earnings per share:
Basic 73,970 72,912 68,545
=========== ========== ==========
Diluted 74,648 73,872 69,592
=========== ========== ==========
(g) Other Assets
Other assets consist primarily of debt acquisition costs. Debt
acquisition costs are being amortized over the term of the related
debt, which is from four to twenty years. The amortization of debt
acquisition costs, which is classified as interest expense, was
$1,026,000, $1,031,000, and $1,269,000 for the years ended December 31,
2003, 2002 and 2001, respectively. Accumulated amortization of other
assets is $3,074,000 and $2,756,000 at December 31, 2003 and 2002,
respectively.
30
(h) Decommissioning Liability
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 clear the sites,
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
completely abandoned. The recorded liability is first reduced by all
cash expenses incurred to abandon and decommission the property. If the
recorded liability exceeds (or is less than) the Company's
out-of-pocket costs, then the difference is reported as income (or
loss) in 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
liabilities recorded, which in turn would increase the carrying values
of the related oil and gas properties.
(i) 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 Company's rental tools are
leased 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.
(j) 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 for financial reporting purposes and such amounts as measured by
tax laws.
(k) 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 the potential shares that would have a dilutive effect on
earnings per share.
(l) Financial Instruments
The fair value of the Company's financial instruments of cash, accounts
receivable and current maturities of long-term debt approximates their
carrying amounts. The fair value of the Company's long-term debt is
approximately $270.5 million at December 31, 2003.
On occasion, the Company uses interest rate swap agreements to manage
its interest rate exposure. The Company specifically designates these
agreements as cash flow hedges of debt instruments and recognizes
interest differentials as adjustments to interest expense in the period
the differentials occur. Under interest rate swap agreements, the
Company agrees with other parties to exchange at specific intervals,
the difference between fixed-rate and variable-rate interest amounts
calculated by reference to an agreed-upon notional principal amount. No
such agreements were outstanding at December 31, 2003.
31
(m) Foreign Currency Translation
Assets and liabilities of the Company's 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.
(n) Stock Based Compensation
The Company accounts for its stock based compensation under the
principles prescribed by the Accounting Principles Board's Opinion No.
25, "Accounting for Stock Issued to Employees" (Opinion No. 25).
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 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. As required by
Statement of Financial Accounting Standards No. 148 (FAS No. 148),
"Accounting for Stock Based Compensation - Transition and Disclosure",
which amended FAS No. 123, the following table illustrates the effect
on net income and earnings per share if the Company had applied the
fair value recognition provisions of FAS No. 123 to a stock based
employee compensation. 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).
2003 2002 2001
------------ ------------ -------------
Net income, as reported $ 30,514 $ 21,886 $ 53,776
Stock-based employee compensation (2,671) (3,262) (2,582)
expense, net of tax
----------- ----------- ------------
Pro forma net income $ 27,843 $ 18,624 $ 51,194
=========== =========== ============
Basic earnings per share:
Earnings, as reported $ 0.41 $ 0.30 $ 0.78
Stock-based employee compensation
expense, net of tax (0.04) (0.04) (0.03)
----------- ----------- ------------
Pro forma earnings per share $ 0.37 $ 0.26 $ 0.75
=========== =========== ============
Diluted earnings per share:
Earnings, as reported $ 0.41 $ 0.30 $ 0.77
Stock-based employee compensation (0.04) (0.05) (0.03)
expense, net of tax
----------- ----------- ------------
Pro forma earnings per share $ 0.37 $ 0.25 $ 0.74
=========== =========== ============
Black-Scholes option pricing model assumptions:
Risk free interest rate 2.65% 2.94% 4.50%
Expected life (years) 3 3 3
Volatility 58.61% 85.48% 79.11%
Dividend yield - - -
32
(2) Change in Accounting Principle
On January 1, 2001, the Company changed depreciation methods from the
straight-line method to the units-of-production method on its liftboat fleet to
more accurately reflect the wear and tear of normal use. Management believes
that the units-of-production method is best suited to reflect the actual
depreciation of the liftboat fleet. Depreciation expense calculated under the
units-of-production method may be different than depreciation expense calculated
under the straight-line method in any period. The annual depreciation based on
utilization of each liftboat will not be less than 25% of annual straight-line
depreciation, and the cumulative depreciation based on utilization of each
liftboat will not be less than 50% of cumulative straight-line depreciation. The
cumulative effect of this change in accounting principle on prior years resulted
in an increase in net income for the year ended December 31, 2001 of $2.6
million, net of taxes of $1.7 million, or $0.04 per share.
(3) Supplemental Cash Flow Information (in thousands)
<Table>
<Caption>
2003 2002 2001
------------ ------------ ------------
Cash paid for interest $ 23,633 $ 22,006 $ 17,329
============ ============ ============
Cash paid (received) for income taxes $ (4,125) $ (15,224) $ 20,304
============ ============ ============
Details of acquisitions:
Fair value of assets $ 90,612 $ 29,985 $ 141,946
Fair value of liabilities (74,779) (22,093) (26,957)
Common stock issued -- -- (6,218)
------------ ------------ ------------
Cash paid 15,833 7,892 108,771
Less cash acquired (1,535) (239) (3,772)
------------ ------------ ------------
Net cash paid for acquisitions $ 14,298 $ 7,653 $ 104,999
============ ============ ============
Non-cash investing activity:
Additional consideration payable
on acquisitions $ 11,263 $ 660 $ 3,750
============ ============ ============
Note receivable from asset disposition $ 938 $ -- $ --
============ ============ ============
</Table>
(4) Other Income
As the result of a tropical storm, one of the Company's 200-foot class liftboats
sank in the Gulf of Mexico on June 30, 2003. During the third quarter of 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.
(5) Acquisitions and Dispositions
On August 15, 2003, the Company acquired Premier Oilfield Services, Ltd.
(Premier), an Aberdeen, Scotland-based provider of oilfield equipment rentals,
in order to geographically expand the Company's operations and the rental tool
segment. The Company paid $3.4 million in cash consideration, including
transaction costs, and an additional $29.0 million to repay its existing debt,
concurrently with the acquisition. The acquisition has been accounted for as a
purchase and the acquired assets and liabilities have been valued at their fair
values. The Company has recorded approximately $21.6 million in goodwill related
to this transaction. The results of operations of Premier 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.
33
On August 28, 2003, the Company sold its construction-related assets that were
included in the other oilfield services segment for $1.25 million. The Company
received $312,500 in cash for the sale and a note receivable for the remaining
$937,500. There was no gain or loss recorded on the sale. These assets generated
approximately $19.0 million, $25.8 million and $24.9 million of the Company's
revenues in the years ended December 31, 2003, 2002 and 2001, respectively.
In December 2003, the Company acquired oil and gas properties in order to
provide additional opportunities for its well intervention and platform
management businesses. Under the terms of the transaction, the Company acquired
the properties and assumed the decommissioning liability. The Company received a
commitment from the seller towards the abandonment of the properties and will
invoice the seller at agreed upon prices as the decommissionings (abandonment
and structure removal) are completed. The Company recorded notes receivable of
$33.4 million and a decommissioning liability of $38.9 million. Oil and gas
producing assets were recorded at their estimated fair value of $5.5 million,
approximating the value of the decommissioning liabilities assumed less amounts
receivable.
In the year ended December 31, 2002, the Company made two acquisitions. In
January, the Company acquired an environmental services company by converting
$18.6 million of notes and other receivables into ownership of the company. In
December, the Company acquired a rental tool business for $5.6 million in cash
consideration. The Company paid an additional $928,000 for this acquisition in
the second quarter of 2003 in conjunction with the receipt of the title to a
facility for this business. Both of these acquisitions have been accounted for
as purchases and the results of operations have been included from the
respective acquisition dates.
Most of the Company's business acquisitions have involved additional contingent
consideration based upon a multiple of the acquired companies' respective
average earnings before interest, income taxes, depreciation and amortization
expense (EBITDA) over a three-year period from the respective date of
acquisition. While the amounts of additional consideration payable depend upon
the acquired company's operating performance and are difficult to predict
accurately, the maximum additional consideration payable for the Company's
remaining acquisitions will be approximately $16.1 million, which will be
determined in the second quarter of 2004 and payable during the second half of
2004. These amounts are not classified as liabilities under generally accepted
accounting principles and are not reflected in the Company's financial
statements until the amounts are fixed and determinable. With the exception of
the Company's guarantee of the Lamb Energy Services, L.L.C. (Lamb Energy) credit
facility (see note 7 to the consolidated financial statements), 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
amounts are determined, they are capitalized as part of the purchase price of
the related acquisition. In the year ended December 31, 2003, the Company
capitalized additional consideration of $22.7 million related to five of its
acquisitions, of which $11.5 million was paid during 2003 and $11.2 million is
expected to be paid in the first half of 2004.
34
(6) Property, Plant and Equipment
A summary of property, plant and equipment at December 31, 2003 and 2002 (in
thousands) is as follows:
2003 2002
---- ----
Buildings and improvements $ 49,964 $ 30,135
Marine vessels and equipment 188,056 191,848
Machinery and equipment 297,601 261,521
Oil and gas producing assets 5,468 -
Automobiles, trucks, tractors and trailers 10,482 11,808
Furniture and fixtures 9,948 7,461
Construction-in-progress 2,594 14,116
Land 6,148 4,778
------------ ------------
570,261 521,667
Accumulated depreciation (142,901) (103,620)
------------ ------------
Property, plant and equipment, net $ 427,360 $ 418,047
============ ============
Amounts of property, plant and equipment leased to third parties at December 31,
2003 and 2002 were not material.
(7) Investments in Affiliates
In June 2002, the Company contributed a note receivable of $8.9 million and
fixed assets with an approximate $2.6 million net book value to obtain a 54.3%
equity ownership interest in Lamb Energy, a rental tool company. The Company is
accounting for its investment under the equity method of accounting, as it does
not have voting or operational control of Lamb Energy. Investments in affiliates
also include a 50% ownership interest in a company that owns an airplane. The
equity in income from these investments was approximately $985,000 for the year
ended December 31, 2003 and a loss of approximately $80,000 for the year ended
December 31, 2002. The summarized financial information of the aggregate of
these entities is not material to the financial position or results of
operations of the Company.
35
(8) Debt
Long-Term Debt
The Company's long-term debt as of December 31, 2003 and 2002 consisted of the
following (in thousands):
2003 2002
---- ----
Senior Notes - interest payable semiannually
at 8.875%, due May 2011 $ 200,000 $ 200,000
Term Loans - interest payable monthly at floating rate
(3.51% at December 31, 2003), due in quarterly installments of $3.35 million
through March 2005 then $1.75 million
through June 2008 with $11.2 million due May 2005 50,700 40,800
Revolver - interest payable monthly at floating rate,
due in August 2006 - 9,250
U.S. Government guaranteed long-term financing - interest
payable semianually at 6.45%, due in semiannual
installments through June 2027 19,026 19,836
Other installment notes payable - 178
--------- ---------
269,726 270,064
Less current portion 14,210 13,730
--------- ---------
Long-term debt $ 255,516 $ 256,334
========= =========
The Company has outstanding $200 million of 8 7/8% 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
indenture governing the senior notes contains certain covenants that, among
other things, prevents 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 $147 million at December 31, 2003.
The indenture also contains covenants that restrict the Company's ability to
create certain liens, sell assets, or enter into certain mergers or
acquisitions.
The Company also has a bank credit facility. In August 2003, the Company amended
the facility to, among other things, increase the amount of the term loans by
$23 million to finance the acquisition of Premier and extend the maturity date
of the facility. At December 31, 2003, the Company has term loans in an
aggregate amount of $50.7 million outstanding and a revolving credit facility of
$75 million, none of which was outstanding. The term loans require principal
payments of $3.4 million each quarter through March 31, 2005 and $1.8 million
each quarter from June 30, 2005 through June 30, 2008. A lump sum payment of
$11.2 million is due on May 2, 2005 and any balance outstanding on the revolving
credit facility is due on August 13, 2006. The credit facility bears interest at
a LIBOR rate plus margins that depend on the Company's leverage ratio.
Indebtedness under the credit facility is secured by substantially all of the
Company's assets, including the pledge of the stock of the Company's principal
subsidiaries. The credit facility contains customary events of default and
requires that the Company satisfy various financial covenants. It also limits
the Company's capital expenditures, its ability to pay dividends or make other
distributions, make acquisitions, make changes to the Company's capital
structure, create liens or incur additional indebtedness.
The Company has $19.0 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 Company's 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.
36
The Company owns a 54.3% interest in Lamb Energy, which has a credit facility
with a syndicate of banks that matures in 2005 consisting of a term loan in the
amount of $9 million outstanding at December 31, 2003, and a revolving credit
facility of $3 million, $500,000 of which was outstanding at December 31, 2003.
The Company fully guarantees amounts due under the credit facility. The Company
does not expect to incur any losses as a result of the guarantee.
Annual maturities of long-term debt for each of the five fiscal years following
December 31, 2003 are as follows (in thousands):
2004 $ 14,210
2005 20,610
2006 7,810
2007 7,810
2008 4,310
Thereafter 214,976
---------
Total $ 269,726
=========
(9) Income Taxes
The components of income tax expense, before the income tax effect of the
extraordinary loss and cumulative effect of change in accounting principle, for
the years ended December 31, 2003, 2001 and 2000 are as follows (in thousands):
2003 2002 2001
---- ---- ----
Current
Federal $ 515 $ (5,042) $ 9,706
State 245 199 -
Foreign 2,365 875 -
-------- -------- --------
3,125 (3,968) 9,706
-------- -------- --------
Deferred
Federal 14,561 16,801 22,991
State 1,220 868 2,874
Foreign (598) - -
-------- -------- --------
15,183 17,669 25,865
-------- -------- --------
$ 18,308 $ 13,701 $ 35,571
======== ======== ========
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):
2003 2002 2001
---- ---- ----
Computed expected tax expense $ 17,088 $ 12,456 $ 30,366
Increase resulting from:
Goodwill amortization - - 1,306
State and foreign income taxes 478 1,068 1,808
Other 742 177 2,091
-------- -------- ---------
Income tax expense $ 18,308 $ 13,701 $ 35,571
======== ======== ========
37
The significant components of deferred income taxes at December 31, 2003 and
2002 are as follows (in thousands):
2003 2002
---- ----
Deferred tax assets:
Allowance for doubtful accounts $ 951 $ 1,069
Alternative minimum tax credit and net
operating loss carryforward 15,481 7,696
Other 2,184 1,096
--------------- ---------------
Net deferred tax assets 18,616 9,861
--------------- ---------------
Deferred tax liabilities:
Property, plant and equipment 93,218 69,322
Other 11,649 7,872
--------------- ---------------
Deferred tax liabilities 104,867 77,194
--------------- ---------------
Net deferred tax liability $ 86,251 $ 67,333
=============== ===============
There was no net change in the valuation allowance for the year ended December
31, 2003 and there was a decrease of $279,000 for the year ended December 31,
2002. The net deferred tax assets reflect management's 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.
As of December 31, 2003, the Company had an estimated $17.2 million net
operating loss to carryforward, which is available to reduce future Federal
taxable income with expiration dates from 2008 through 2023, an estimated $2.8
million alternative minimum tax credit carryforward, and an estimated $1.9
million foreign tax credit carryforward with expiration dates from 2006 through
2008. The Company also had various state net operating loss carryforwards of an
estimated $58 million with expiration dates through 2013.
(10) Stockholders' Equity
In March 2002, the Company sold 4.2 million shares of common stock. The offering
generated net proceeds to the Company of approximately $38.8 million.
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 Company's key
employees, including officers and directors, consultants and advisers to the
Company (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 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 Company's common
stock. The Compensation Committee of the 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 Company's 1995 Stock Incentive
Plan's options which have been granted are vested.
38
A summary of stock options granted under the incentive plans for the years ended
December 31, 2003 and 2002 is as follows:
2003 2002 2001
--------------------------- --------------------------- --------------------------
Weighted Weighted Weighted
Number Average Number Average Number Average
of Share Price of Share Price of Share Price
------------ ------------ ------------ ------------- ------------- -----------
Outstanding at beginning
of year 5,518,516 $ 7.33 5,308,215 $ 7.05 4,334,363 $ 6.10
Granted 538,000 $ 8.94 655,841 $ 9.39 1,917,500 $ 8.48
Exercised (271,913) $ 6.72 (290,665) $ 5.96 (690,648) $ 5.38
Forfeited (156,603) $ 7.00 (154,875) $ 8.89 (253,000) $ 6.18
------------ ------------ -------------
Outstanding at end of year 5,628,000 $ 7.53 5,518,516 $ 7.33 5,308,215 $ 7.05
============ ============ ============ ============= ============= ============
Exercisable at end of year 4,248,244 $ 7.08 3,509,008 $ 6.61 2,968,689 $ 6.15
============ ============ ============ ============= ============= ============
Available for future grants 1,401,101 1,782,498 883,464
============ ============ =============
Average fair value of grants
during the year $ 3.59 $ 5.33 $ 4.44
============ ============= ============
A summary of information regarding stock options outstanding at December 31,
2003 is as follows:
Options Outstanding Options Exercisable
-------------------------------------------------- --------------------------------
Range of Remaining Weighted Weighted
Exercise Contractual Average Average
Prices Shares Life Price Shares Price
- ----------------------------------------------------------------------------------------------------------
$2.50 - $3.43 125,500 2-3 years $ 2.91 125,500 $ 2.91
$4.75 - $5.75 1,827,517 0.5-5.5 years $ 5.68 1,827,517 $ 5.68
$7.06 - $9.00 2,086,354 4-9.5 years $ 7.91 1,371,803 $ 7.64
$9.25-$12.45 1,588,629 1.5-9.5 years $ 9.51 923,424 $ 9.59
(11) Profit-Sharing Plan
The Company maintains a defined contribution profit-sharing plan for employees
who have satisfied minimum service and age requirements. Employees may
contribute up to 50% of their earnings to the plans. The Company provides a
discretionary match, not to exceed 5% of an employee's salary. The Company made
contributions of approximately $1.6 million, $1.7 million, and $1.1 million in
2003, 2002 and 2001, respectively.
(12) Financial Instruments
The Company adopted Statement of Financial Accounting Standards No. 133 (FAS No.
133), "Accounting for Derivative Instruments and Hedging Activities," effective
January 1, 2001. The Company uses interest rate swap agreements to manage its
interest rate exposure. Under interest rate swap agreements, the Company agrees
with other parties to exchange at specific intervals, the difference between
fixed-rate and variable-rate interest amounts calculated by reference to an
agreed-upon notional principal amount. As of December 31, 2001, the Company was
party to an interest rate swap with an approximate notional amount of $1.8
million designed to convert a similar amount of variable-rate debt to fixed
rates. The interest rate was 5.675%, and the swap matured in October 2002.
The Company's interest rate swap qualified for cash flow hedge accounting
treatment under FAS No. 133, whereby changes in fair value have been recognized
in accumulated other comprehensive income (a component of stockholders' equity)
until settled, when the resulting gains and losses will be recorded in earnings.
The effect on the Company's earnings and other comprehensive income vary from
period to period and will be dependent upon
39
prevailing interest rates. During 2002 and 2001, losses of approximately $32,000
and $25,000, respectively, were transferred from accumulated other comprehensive
income. At December 31, 2001, the Company recorded a payable of approximately
$30,000 and a corresponding charge to accumulated other comprehensive loss of
approximately $18,000, net of income tax. No such agreements were outstanding at
December 31, 2003 or 2002.
(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 $2.3 million in 2003, $3.0 million
in 2002, and $2.2 million in 2001. Future minimum lease payments under
non-cancelable leases for the five years ending December 31, 2004 through 2008
and thereafter are as follows: $4,275,000, $2,796,000, $1,879,000, $1,359,000,
$641,000 and $12,423,000, respectively. Future minimum lease payments receivable
under non-cancelable sub-leases for the five years ending December 31, 2004
through 2008 are as follows: $581,000, $576,000, $535,000, $472,000, and
$39,000, respectively.
From time to time, the Company is involved in litigation arising out of
operations in the normal course of business. In management's opinion, the
Company is not involved in any litigation, the outcome of which would have a
material effect on the financial position, results of operations or liquidity of
the Company.
(14) Related Party Transactions
The Company provides field management and other services to an independent oil
and gas exploration and production company, of which a member of the Company's
Board of Directors is Chief Executive Officer. The Company billed this customer
approximately $4 million in each of 2003, 2002 and 2001 on terms that the
Company believes are customary in the industry. The Company expects to continue
providing services to this customer.
The Company leased a plane acquired in November 2001 for business travel from a
company in which the President and Chief Executive Officer then owned a 50%
interest. The lease provided that the Company would make monthly lease payments
of $14,250 and pay all of the plane's operating and maintenance costs. The
Company expensed $16,625 for the use of the plane during the 2001 fiscal year,
and $15,600 in operating and maintenance costs. Effective December 31, 2001, the
Company bought the Chief Executive Officer's interest in the company that owns
the plane for $900,000, the same price that he paid for his interest in November
2001.
(15) Segment Information
Business Segments
The Company's reportable segments are as follows: well intervention, marine,
rental tools, and other oilfield services. Each segment offers 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 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 well intervention segment
also includes sales of oil and gas. The marine segment operates liftboats for
oil and gas production facility maintenance, construction operations and
platform removals, as well as production service activities. 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
other oilfield services segment provides contract operations and maintenance
services, interconnect piping services, sandblasting and painting 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 manufactures
and sells drilling instrumentation and oil spill containment equipment. All the
segments operate primarily in the Gulf of Mexico.
The accounting policies of the reportable segments are the same as those
described in Note 1 of the 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
40
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 Company's segments as of
December 31, 2003, 2002 and 2001 and for the years then ended is shown in the
following tables (in thousands):
Well Rental Other Oilfield Unallocated Consolidated
2003 Intervention Marine Tools Services Amount Total
- ---- ---------------------------------------------------------------------------------------
Identifiable assets $ 265,337 $ 181,752 $ 314,122 $ 64,421 $ 7,231 $ 832,863
Capital expenditures 15,248 2,043 30,192 2,692 - 50,175
Revenues $ 188,012 $ 70,370 $ 141,362 $ 100,881 $ - $ 500,625
Costs of services 111,661 50,314 46,119 81,513 - 289,607
Depreciation and amortization 12,362 6,665 25,696 4,130 - 48,853
General and administrative 39,600 7,122 33,457 14,643 - 94,822
Operating income 24,389 6,269 36,090 595 - 67,343
Interest expense - - - - (22,477) (22,477)
Interest income - - - - 209 209
Other income - 2,762 - - 2,762
Equity in earnings of affiliates - - 985 - - 985
---------------------------------------------------------------------------------------
Income (loss) before income
taxes $ 24,389 $ 9,031 $ 37,075 $ 595 $ (22,268) $ 48,822
=======================================================================================
Well Rental Other Oilfield Unallocated Consolidated
2002 Intervention Marine Tools Services Amount Total
- ---- ---------------------------------------------------------------------------------------
Identifiable assets $ 199,084 $ 195,832 $ 261,341 $ 63,491 $ 7,872 $ 727,620
Capital expenditures 18,058 38,833 41,931 5,630 - 104,452
Revenues $ 148,670 $ 67,884 $ 124,085 $ 102,508 $ - $ 443,147
Costs of services 93,474 44,648 38,375 81,837 - 258,334
Depreciation and amortization 10,625 6,764 19,822 4,384 - 41,595
General and administrative 34,520 7,463 29,846 14,368 - 86,197
Operating income 10,051 9,009 36,042 1,919 - 57,021
Interest expense - - - - (21,884) (21,884)
Interest income 530 530
Equity in loss of affiliates - - (80) - - (80)
---------------------------------------------------------------------------------------
Income (loss) before income
taxes $ 10,051 $ 9,009 $ 35,962 $ 1,919 $(21,354) $ 35,587
=======================================================================================
41
Well Rental Other Oilfield Unallocated Consolidated
2001 Intervention Marine Tools Services Amount Total
- ---- ---------------------------------------------------------------------------------------
Identifiable assets $ 200,512 $ 165,057 $ 233,733 $ 58,775 $ 7,443 $ 665,520
Capital expenditures 22,300 22,091 36,274 3,198 - 83,863
Revenues $ 171,223 $ 71,406 $ 121,742 $ 84,671 $ - $ 449,042
Costs of services 95,549 34,473 40,929 66,404 - 237,355
Depreciation and amortization 9,449 4,729 16,382 2,886 - 33,446
General and administrative 29,521 6,134 26,883 10,750 - 73,288
Operating income 36,704 26,070 37,548 4,631 - 104,953
Interest expense - - - - (20,087) (20,087)
Interest income - - - - 1,892 1,892
---------------------------------------------------------------------------------------
Income (loss) before income
taxes and cumulative effect of
change in accounting principle $ 36,704 $ 26,070 $ 37,548 $ 4,631 $(18,195) $ 86,758
=======================================================================================
Geographic Segments
The Company attributes revenue to various countries based on the location of the
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 Company's information by geographic area is as
follows (amounts in thousands):
<Table>
<Caption>
Revenues Long-Lived Assets
------------------------------------ ----------------------
Years Ended December 31, December 31,
2003 2002 2001 2003 2002
---- ---- ---- ---- ----
United States $ 443,936 $ 404,295 $ 425,443 $ 400,600 $ 407,798
Other Countries 56,689 38,852 23,599 26,760 10,249
----------------------------------- ----------------------
Total $ 500,625 $ 443,147 $ 449,042 $ 427,360 $ 418,047
=================================== ======================
</Table>
42
(16) Interim Financial Information (Unaudited)
The following is a summary of consolidated interim financial information for the
years ended December 31, 2003 and 2002 (amounts in thousands, except per share
data):
Three Months Ended
-----------------------------------------------
March 31 June 30 Sept. 30 Dec. 31
-------- ------- -------- -------
2003
- ----
Revenues $ 123,195 $ 128,857 $ 128,316 $ 120,257
Gross profit 53,038 54,566 52,867 50,547
Net income 7,507 8,328 8,826 5,853
Earnings per share:
Basic $ 0.10 $ 0.11 $ 0.12 $ 0.08
Diluted 0.10 0.11 0.12 0.08
Three Months Ended
-----------------------------------------------
March 31 June 30 Sept. 30 Dec. 31
-------- ------- -------- -------
2002
- ----
Revenues $ 104,826 $ 112,730 $ 107,213 $ 118,378
Gross profit 45,588 50,590 40,077 48,558
Net income 5,825 8,505 1,946 5,610
Earnings per share:
Basic $ 0.08 $ 0.12 $ 0.03 $ 0.08
Diluted 0.08 0.11 0.03 0.08
(17) Accounting Pronouncements
In January 2003, the Financial Accounting Standards Board issued FASB
Interpretation No. 46 (FIN 46), "Consolidation of Variable Interest Entities."
FIN 46 clarifies the application of Accounting Research Bulletin Number 51,
"Consolidated Financial Statements," to certain entities in which equity
investors do not have the characteristics of a controlling financial interest or
do not have sufficient equity at risk for the entity to finance its activities
without additional subordinated financial support from other parties. In
December 2003, the Financial Accounting Standards Board issued modifications to
FIN 46 (FIN 46R), resulting in multiple effective dates based on the nature as
well as the creation date of a Variable Interest Entity. The Company does not
expect the adoption of FIN 46 or FIN 46R to have a significant effect on its
financial position or results of operations.
In April 2003, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 149 (FAS No. 149), "Amendment of Statement
133 on Derivative Instruments and Hedging Activities." FAS No. 149 amends and
clarifies financial accounting and reporting for derivative instruments,
including certain derivative instruments embedded in other contracts
(collectively referred to as derivatives) and for hedging activities under
Statement of Financial Accounting Standards No. 133 (FAS No. 133), "Accounting
for Derivative Instruments and Hedging Activities." FAS No. 149 is effective for
contracts entered into or modified after September 30, 2003. The adoption of FAS
No. 149 did not have a significant effect on the Company's financial position or
results of operations.
In May 2003, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 150 (FAS No. 150), "Accounting for Certain
Financial Instruments with Characteristics of Both Liabilities and Equity." FAS
No. 150 establishes standards for the classification and measurement of certain
financial instruments with characteristics of both liabilities and equity. FAS
No. 150 is effective for financial instruments entered into or modified after
May 31, 2003. The adoption of FAS No. 150 did not have a significant effect on
the Company's financial position or results of operations.
43
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None
ITEM 9A. CONTROLS AND PROCEDURES
As of the end of the period covered by this annual report, we have evaluated the
effectiveness of the design and operation of our disclosure controls and
procedures pursuant to Rule 13(a)-15(e) of the Securities Exchange Act of 1934.
This evaluation was carried out under the supervision and with the participation
of our management, including our principal executive officer and principal
financial officer. Based on this evaluation, these officers have concluded that,
as of December 31, 2003, our disclosure controls and procedures are functioning
effectively to provide 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 SEC's rules and forms. There has been no change in our internal controls
over financial reporting during the quarter ended December 31, 2003 that has
materially affected, or is reasonably likely to materially affect, our internal
controls over financial reporting.
Disclosure controls and procedures are our controls and other procedures that
are designed to ensure that information required to be disclosed by us in the
reports that we file or submit under the Securities Exchange Act of 1934, such
as this annual report, is recorded, processed, summarized and reported, within
the time periods specified in the SEC's rules and forms. Disclosure controls and
procedures include, without limitation, controls and procedures designed to
ensure that information required to be disclosed by us in the reports that we
file under the Securities Exchange Act of 1934 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.
44
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information required by this item will be included in an amendment to this Form
10-K or incorporated by reference from the registrant's 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 included in an amendment to this Form
10-K or incorporated by reference from the registrant's 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 included in an amendment to this Form
10-K or incorporated by reference from the registrant's 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 included in an amendment to this Form
10-K or incorporated by reference from the registrant's 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 included in an amendment to this Form
10-K or incorporated by reference from the registrant's definitive proxy
statement to be filed pursuant to Regulation 14A and is incorporated herein by
reference.
45
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) (1) Financial Statements
The following financial statements are Included in Part II of this Report:
Independent Auditors' Report
Consolidated Balance Sheets - December 31, 2003 and 2002
Consolidated Statements of Operations for the years ended December 31,
2003, 2002 and 2001
Consolidated Statements of Changes in Stockholders' Equity for the years
ended December 31, 2003, 2002 and 2001
Consolidated Statements of Cash Flows for the years ended December 31,
2003, 2002 and 2001
Notes to Consolidated Financial Statements
(2) Financial Statement Schedules
Schedule II - Valuation and Qualifying accounts for the years ended
December 31, 2003, 2002 and 2001
(3) Exhibits
The exhibits filed as part of this Form 10-K are listed on the Index to
Exhibits immediately preceding such exhibits, which index is incorporated
herein by reference.
(b) Reports on Form 8-K
On November 4, 2003, the Company filed a current report on Form 8-K
reporting, under Item 5, the results for the third quarter ended September
30, 2003.
On December 18, 2003, the Company filed a current report on Form 8-K
reporting, under Item 5, that its subsidiary SPN Resources, LLC acquired
oil and gas properties.
46
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,
Chief Executive Officer and
President
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, March 12, 2004
- ---------------------------------- Chief Executive Officer and President
TERENCE E. HALL (Principal Executive Officer)
/s/ Robert S. Taylor Vice President and March 12, 2004
- ---------------------------------- Chief Financial Officer
ROBERT S. TAYLOR (Principal Financial and Accounting Officer)
/s/ Richard A. Bachmann Director March 12, 2004
- ----------------------------------
RICHARD A. BACHMANN
/s/ Enoch L. Dawkins Director March 12, 2004
- ----------------------------------
ENOCH L. DAWKINS
/s/ Joseph R. Edwards Director March 12, 2004
- ----------------------------------
JOSEPH R. EDWARDS
/s/ Ben A. Guill Director March 12, 2004
- ----------------------------------
BEN A. GUILL
/s/ Richard A. Pattarozzi Director March 12, 2004
- ----------------------------------
RICHARD A. PATTAROZZI
/s/ Justin L. Sullivan Director March 12, 2004
- ----------------------------------
JUSTIN L. SULLIVAN
47
SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Schedule II Valuation and Qualifying Accounts Years Ended
December 31, 2003, 2002 and 2001
(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, 2003:
Allowance for doubtful accounts $ 4,617 $ 2,359 $ - $ 696 $ 6,280
Year ended December 31, 2002:
Allowance for doubtful accounts $ 4,057 $ 2,073 $ 133 $ 1,646 $ 4,617
Year ended December 31, 2001:
Allowance for doubtful accounts $ 2,292 $ 2,854 $ 3 $ 1,092 $ 4,057
48
INDEX TO EXHIBITS
Exhibit No. DESCRIPTION Seq. No.
- ---------- ----------- -------
3.1 Certificate of Incorporation of the Company (incorporated herein by
reference to the Company's Quarterly Report on Form 10-QSB for the quarter
ended March 31, 1996).
3.2 Certificate of Amendment to the Company's Certificate of Incorporation
(incorporated herein by reference to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 1999).
3.3 Amended and Restated Bylaws (incorporated herein by reference to the
Company's Quarterly Report on Form 10-Q for the quarter ended June 30,
1999).
4.1 Specimen Stock Certificate (incorporated herein by reference to Amendment
No. 1 to the Company's Form S-4 on Form SB-2 (Registration Statement No.
33-94454)).
4.2 Registration Rights Agreement dated as of July 15, 1999 by and among the
Company, First Reserve Fund VII, Limited Partnership and First Reserve Fund
VIII, Limited Partnership (incorporated herein by reference to the
Company's Quarterly Report on Form 10-Q for the quarter ended June 30,
1999).
4.3 Stockholders' Agreement dated as of July 15, 1999 by and
among the Company, First Reserve Fund VII, Limited
Partnership and First Reserve Fund VIII, Limited Partnership
(incorporated herein by reference to the Company's Quarterly
Report on Form 10-Q for the quarter ended June 30, 1999).
4.4 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 Company's 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 Company's
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 Company's Quarterly Report on Form 10-Q for the quarter ended September
30, 2001).
10.1 Superior Energy Services, Inc. 1995 Stock Incentive Plan (incorporated
herein by reference to Exhibit A to the Company's Definitive Proxy
Statement dated June 25, 1997).
10.2 Superior Energy Services, Inc. 1999 Stock Incentive Plan as amended
(incorporated herein by reference to the Company's Annual Report on Form
10-K for the year ended December 31, 1999).
49
Exhibit No. DESCRIPTION Seq. No.
- ---------- ----------- -------
10.3 Amended and Restated Credit Agreement dated as of August 13,
2003 among SESI, L.L.C., as borrower, Superior Energy
Services, Inc., as parent, Bank One, NA as agent, Wells Fargo
Bank Texas, N.A. as syndication agent, Whitney National Bank
as documentation agent, and the lenders party thereto
(incorporated herein by reference to the Company's Quarterly
Report on Form 10-Q for the quarter ended September 30,
2003).
10.4 Employment Agreement between the Company and Terence Hall
(incorporated herein by reference to the Company's Annual
Report on Form 10-K for the year ended December 31, 1999).
10.5 Amended and Restated Employment and Non-Competition Agreement
between the Company and Robert Taylor dated July 15, 2001
(incorporated herein by reference to the Company's Annual
Report on Form 10-K for the year ended December 31, 2001).
10.6 Amended and Restated Employment and Non-Competition Agreement
between the Company and Kenneth Blanchard dated July 15, 2001
(incorporated herein by reference to the Company's Annual
Report on Form 10-K for the year ended December 31, 2001).
10.7 Purchase Agreement, dated December 31, 2001 between SESI, L.L.C. and
Terence E. Hall (incorporated herein by reference to the Company's Annual
Report on Form 10-K for the year ended December 31, 2001).
10.8 Superior Energy Services, Inc. Directors' Stock Plan dated April 30, 2000
(incorporated herein by reference to the Company's Annual Report on Form
10-K for the year ended December 31, 2002).
10.9* Amended and Restated Superior Energy Services, Inc. 2002 Stock Incentive
Plan.
10.10 First Amendment to Stockholders' Agreement dated March 31,
2003 by and among Superior Energy Services, Inc., First
Reserve Fund VII, Limited Partnership, and First Reserve Fund
VIII, Limited Partnership (incorporated herein by reference
to the Company's Quarterly Report on Form 10-Q for the
quarter ended March 31, 2003).
14.1 Code of business ethics and conduct.
21.1* Subsidiaries of the Company.
23.1* Consent of KPMG LLP.
31.1* Officer's certification pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
31.2* Officer's certification pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
32.1* Officer's certification pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002.
50
Exhibit No. DESCRIPTION Seq. No.
- ---------- ----------- -------
32.2* Officer's certification pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002.
*Filed herein
51