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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

         
(Mark One)
       
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)    
  OF THE SECURITIES EXCHANGE ACT OF 1934    
  For the fiscal year ended December 31, 2004    
  or    
o
  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 þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of 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. o

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 þ No o

The aggregate market value of the voting stock held by non-affiliates of the Registrant at June 30, 2004 based on the closing price on the New York Stock Exchange on that date was $779,132,000.

The number of shares of the Registrant’s common stock outstanding on February 28, 2005 was 77,554,214.

DOCUMENTS INCORPORATED BY REFERENCE

Certain information called for by Item 5 of Part II and Items 10, 11, 12, 13 and 14 of Part III will be incorporated by reference from the Registrant’s definitive proxy statement to be filed pursuant to Regulation 14A.

 
 

 


SUPERIOR ENERGY SERVICES, INC.
Annual Report on Form 10-K for
the Fiscal Year Ended December 31, 2004

TABLE OF CONTENTS

             
        Page
           
 
           
  Business and Properties     1  
  Legal Proceedings     17  
  Submission of Matters to a Vote of Security Holders     17  
  Executive Officers of Registrant     17  
 
           
           
 
           
  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     18  
  Selected Financial Data     19  
  Management's Discussion and Analysis of Financial Condition and Results of Operations     20  
  Quantitative and Qualitative Disclosures about Market Risk     30  
  Financial Statements and Supplementary Data     32  
  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     60  
  Controls and Procedures     60  
  Other Information     61  
 
           
           
 
           
  Directors and Executive Officers of the Registrant     62  
  Executive Compensation     62  
  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     62  
  Certain Relationships and Related Transactions     62  
  Principal Accountant Fees and Services     62  
 
           
           
 
           
  Exhibits and Financial Statement Schedules     63  
 3rd Amend. to Amended and Restated Credit Agreement
 Nonqualified Deferred Compensation Plan
 Subsidiaries of the Company
 Consent of KPMG LLP
 Consent of DeGolyer and MacNaughton
 Officer's certification pursuant to Rules 13a-14a/15d-14a
 Officer's certification pursuant to Rules 13a-14a/15d-14a
 Officer's certification pursuant to Section 1350
 Officer's certification pursuant to Section 1350

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FORWARD-LOOKING STATEMENTS

In addition to historical information, this Annual Report on Form 10-K contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act. In particular, these include statements related to future actions, future performance or results of current and anticipated initiatives and the outcome of contingencies and other uncertainties. We try, whenever possible, to identify such statements by using words such as “anticipate,” “believe,” “estimate,” “expect,” “plan,” “project” and similar expressions. We caution you that these statements are only predictions and are not guarantees of future performance. These forward-looking statements and our actual results, developments and business are subject to certain risks and uncertainties that could cause actual results and events to differ materially from those anticipated by these statements.

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 primarily in the Gulf of Mexico and the drilling-related needs of oil and gas companies in the Gulf of Mexico and in select international market areas. We also own and operate, through our subsidiary SPN Resources, LLC, mature oil and gas properties in the Gulf of Mexico. Our business is organized into five segments consisting of well intervention services, marine services, rental tools, other oilfield services and oil and gas operations. We believe that we are one of the few companies in the Gulf of Mexico capable of providing the services, tools and liftboats necessary to maintain, enhance and extend the life of offshore producing wells, as well as plug and abandonment services at the end of their life cycle. We believe that our ability to provide our customers with multiple services and to coordinate and integrate their delivery allows us to maximize efficiency, reduce lead-time and provide cost-effective solutions for our customers.

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 to our existing business lines. 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.

In December 2003, we began acquiring mature, shallow water oil and gas properties in the Gulf of Mexico to provide our customers with a cost-effective alternative to the decommissioning process. Our main objective in acquiring oil and gas properties is to provide additional opportunities for our well intervention services and our platform management business. We acquire older, more mature properties since they need many of the production-enhancement services we provide. We 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. By owning these properties, we can choose when we perform much of the work, helping increase the utilization of our assets and services. We do not intend to risk capital by participating in exploratory drilling activities.

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. Our well intervention services include coiled tubing, electric wireline, mechanical wireline, pumping and stimulation, artificial lift, well control, snubbing, recompletion, engineering and well evaluation services. We believe we are the leading provider of mechanical wireline services in the Gulf of Mexico with approximately 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.

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 50 liftboats, including 11

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liftboats configured specifically for wireline services and 39 in our rental fleet with leg-lengths ranging from 65 feet to 250 feet. All of our liftboats are currently located in the Gulf of Mexico, but we will reposition some of our larger liftboats to international market areas under long-term contracts if 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 27 locations in all major staging points in Louisiana and Texas for offshore oil and gas activities in the Gulf of Mexico. Our rental tool segment also has locations domestically in Oklahoma and Wyoming, and internationally in Venezuela, Trinidad, Mexico, Eastern Canada, the North Sea, the Middle East and West Africa. Our rental tools include pressure control equipment, specialty tubular goods, connecting iron, handling tools, drill pipe, bolting equipment, tongs, power swivels, stabilizers and on-site accommodations.

Other Oilfield Services. We provide a broad range of platform and field management services to the offshore and onshore oil and gas industry, including property management, engineering services, operating labor, transportation, tools and supplies, technical supervision, maintenance, supplemental personnel, and logistics services. We currently provide property management services to approximately 130 offshore facilities in the Gulf of Mexico. We also provide 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.

Oil and Gas Operations. We expanded our operations in December 2003 to include acquiring mature oil and gas properties in the Gulf of Mexico to provide our customers a cost-effective alternative to the decommissioning process. These acquisitions also provide additional opportunities for our well intervention and platform management services and allow us to expand the service offerings of our well intervention, marine and other oilfield services segments from our traditional emphasis on plugging and abandoning wells to include facility salvaging and decommissioning activities by using our liftboat fleet when possible.

Once properties are acquired, we utilize our production-related assets and services to maintain, enhance and extend existing production of these properties. At the end of a property’s economic life, we plug and abandon the wells and decommission and abandon the facilities. As of December 31, 2004, we had interests in 35 offshore blocks containing 64 structures and 350 productive wells, of which approximately 180 were producing.

For additional industry segment financial information, see note 12 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 2004, no customer accounted for more than 10% of our total revenue. In 2003 and 2002, sales to one customer accounted for approximately 11% and 12% of our total revenue, respectively. 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:

  •   changes in competitive prices;
 
  •   oil and gas prices and industry perceptions of future prices;
 
  •   fluctuations in the level of activity by oil and gas producers;
 
  •   changes in the number of liftboats operating in the Gulf of Mexico;
 
  •   the ability of oil and gas producers to generate capital;

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  •   general economic conditions; and
 
  •   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 these companies, as well as several smaller companies that are single source providers of rental tools, are our competitors in the rental tools market. In the marine services segment, we compete with smaller companies that provide liftboat services. We also compete with other companies for the acquisition of mature oil and gas properties in the Gulf of Mexico. We believe that the principal competitive factors in the market areas that we serve are price, product and service quality, safety record, equipment availability and technical proficiency.

Our operations may be adversely affected if our current competitors or new market entrants introduce new products or services with better features, performance, prices or other characteristics than our products and services, or if they would offer to pay more for mature oil and gas properties. Further, if our competitors construct additional liftboats for the Gulf of Mexico market area, it 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.

Health, Safety and Environmental Assurance

We have established health, safety and environmental performance as a corporate priority. Our goal is to be an industry leader in this area by focusing on the belief that all safety and environmental incidents are preventable and an injury-free workplace is achievable by creating a culture that emphasizes correct behavior. We have 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 of our offshore and yard employees. In addition, we investigate all incidents with a priority of identifying and implementing the corrective measures necessary to reduce the chance of reoccurrence.

Potential Liabilities and Insurance

Our operations involve a high degree of operational risk, particularly of environmental accidents, personal injury and damage or loss of equipment. Failure or loss of our equipment could result in property damages, personal injury, environmental pollution and other damage for which we could be liable. Litigation arising from the sinking of a liftboat or a catastrophic occurrence, such as a fire, explosion or well blowout, at one of our offshore production facilities or a location where our equipment and services are used may result in large claims for damages in the future. We maintain insurance against risks that we believe is consistent in types and amounts with industry standards and is required by our customers. Changes in the insurance industry have generally led to higher insurance costs and deductibles, as well as decreased availability of coverage causing us to rely on self insurance against many risks associated with our business. The availability of insurance covering risks we and our competitors typically insure against may continue to decrease forcing us to self insure against more business risks, and the insurance that we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms affecting our operations.

Government Regulation

Our business is significantly affected by the following:

  •   Federal and state laws and other regulations relating to the oil and gas industry;
 
  •   changes in such laws and regulations; and
 
  •   the level of enforcement thereof.

We cannot predict the level of enforcement of existing laws and regulations or how such laws and regulations may be interpreted by enforcement agencies or court rulings in the future. A decrease in the level of industry compliance

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with or enforcement of these laws and regulations in the future may adversely affect the demand for our services. We also cannot predict whether additional laws and regulations will be adopted, or the effect such changes may have on us, our businesses or our financial condition. The demand for our services from the oil and gas industry would be affected by changes in applicable laws and regulations. The adoption of new laws and regulations curtailing drilling for oil and gas in our operating areas for economic, environmental or other policy reasons could also adversely affect our operations by limiting demand for our services.

Regulation of Oil and Gas Production

The oil and gas industry is subject to various types of regulation at federal and state levels. This regulation includes requiring permits to drill wells, maintaining bonding requirements to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, stringent engineering and construction standards, and the plugging and abandoning of wells and removal of production facilities. The oil and gas industry is also subject to various federal and state conservation laws and regulations. These include regulations establishing maximum rates of production from oil and natural gas wells, generally prohibiting the venting or flaring of natural gas and imposing certain requirements regarding the ratability of production.

Virtually all of our oil and gas operations are located on federal oil and gas leases, which are administered by the U.S. Department of Interior, Minerals Management Service, or MMS, pursuant to the Outer Continental Shelf Lands Act, or OCSLA. These leases contain relatively standardized terms. These leases require compliance with detailed MMS regulations and orders that are subject to interpretation and change by MMS. Under some circumstances, MMS may require operations on federal leases to be suspended or terminated.

To cover the various obligations of lessees on the Outer Continental Shelf, MMS generally requires that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be met. The cost of these bonds or assurances can be substantial, and there is no assurance that they can be obtained in all cases. We currently have bonded our offshore leases, as required by MMS, consisting of a $3.0 million Area-Wide Bond plus a $300,000 Pipeline Right-of-Way Bond. Currently we are exempt from supplemental bonding.

MMS also administers the collection of royalties under the terms of the OCSLA and the oil and gas leases issued under the act. The amount of royalties due is based upon the terms of the oil and gas leases as well as of the regulations promulgated by MMS. These regulations are amended from time to time, and the amendments can affect the amount of royalties that we are obligated to pay to MMS. However, we do not believe that these regulations or any future amendments will affect us in a way that materially differs from the way it affects other oil and gas producers.

These regulations impact our customers’ needs for our services, as well as limit the amounts of oil and natural gas we can produce from our wells. Because these statutes, rules and regulations undergo constant review and often are amended, expanded and reinterpreted, we are unable to predict the future cost or impact of regulatory compliance. The regulatory burden on the oil and gas industry increases its cost of doing business and, consequently, affects our profitability.

Natural Gas Marketing, Gathering and Transportation

Historically, the transportation and sales of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978, and Federal Energy Regulatory Commission, or FERC, regulations. The Natural Gas Wellhead Decontrol Act, enacted effective January 1, 1993, deregulated the price for all “first sales” of natural gas. Thus, all of our sales of gas may be made at market prices, subject to applicable contract provisions. Sales of natural gas are affected by the availability, terms and cost of pipeline transportation. FERC has also implemented regulations intended to make natural gas transportation more accessible to gas buyers and sellers on an open-access, non-discriminatory basis.

Certain of our pipeline systems are regulated for safety compliance by the U.S. Department of Transportation, or DOT. Pursuant to the Pipeline Safety Improvement Act of 2002, DOT has implemented regulations intended to increase pipeline operating safety. Among other provisions, the regulations require that pipeline operators

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implement a pipeline integrity management program that must at a minimum include an inspection of gas transmission pipeline facilities within the next ten years, and at least every seven years thereafter.

We cannot predict what new or different regulations FERC, DOT and other regulatory agencies may adopt, or what effect subsequent regulations may have on our activities. Similarly, it is impossible to predict what proposals, if any, that affect the oil and natural gas industry might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on us. Similarly, and despite the recent trend toward federal deregulation of the natural gas industry, whether or to what extent that trend will continue, or what the ultimate effect will be on our sales of gas, cannot be predicted.

Federal Regulation of Petroleum

Our sales of oil and gas are not regulated and are at market prices. The price received from the sale of these products is affected by the cost of transporting the products to market. Much of that transportation is through interstate common carrier pipelines. FERC has implemented regulations approving interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may tend to increase the cost of transporting oil and natural gas by interstate pipeline, although the annual adjustments may result in decreased rates in a given year. Every five years, FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. The next FERC review is scheduled in July 2005. We are not able to predict with certainty the effect upon us of the periodic review by the FERC of the index.

Environmental Regulations

General. Our operations are subject to extensive federal, state and local laws and regulations relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. Permits are required for the conduct of our business and operation of our various marine vessels and offshore production facilities. These permits can be revoked, modified or renewed by issuing authorities. Governmental authorities enforce compliance with their regulations through administrative or civil penalties, corrective action orders, injunctions or criminal prosecution. Government regulations can increase the cost of planning, designing, installing and operating our oil and gas properties. Although we believe that compliance with environmental regulations will not have a material adverse effect on us, risks of substantial costs and liabilities related to environmental compliance issues are part of oil and gas production operations. No assurance can be given that significant costs and liabilities will not be incurred. Also, it is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from oil and gas production could result in substantial costs and liabilities to us.

Federal laws and regulations applicable to our operations include those controlling the discharge of materials into the environment, requiring removal and cleanup of materials that may harm the environment, requiring consistency with applicable coastal zone management plans, or otherwise relating to the protection of the environment.

Our insurance policies provide liability coverage for sudden and accidental occurrences of pollution or clean-up and containment in amounts that we believe are comparable to policy limits carried by others in our industry.

Outer Continental Shelf Lands Act. OCSLA and regulations promulgated pursuant thereto impose a variety of regulations relating to safety and environmental protection applicable to lessees, permits and other parties operating on the Outer Continental Shelf. Specific design and operational standards may apply to Outer Continental Shelf vessels, rigs, platforms, vehicles and structures. Violations of lease conditions or regulations issued pursuant to OCSLA can result in substantial civil and criminal penalties as well as potential court injunctions curtailing operations and the cancellation of leases. Enforcement liabilities under OCSLA can result from either governmental or citizen prosecution. We believe that we substantially comply with OCSLA and its regulations.

Solid and Hazardous Waste. We currently lease numerous properties that have been used in connection with the production of oil and gas for many years. Although operating and disposal practices that were standard in the

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industry at the time they may have been utilized, it is possible that hydrocarbons or other solid wastes may have been disposed of or released on or under the properties currently leased by us. Federal and state laws applicable to oil and gas wastes and properties continue to be stricter over time. Under these increasingly stringent requirements, we could be required to remove or remediate previously disposed wastes (including wastes disposed or released by prior owners and operators) or clean up property contamination (including groundwater contamination by prior owners or operators) or to perform plugging operations to prevent future contamination. We generate some hazardous wastes that are already subject to the Federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes. The Environmental Protection Agency, or the EPA, has limited the disposal options for certain hazardous wastes. It is possible that certain wastes currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes under RCRA or other applicable statutes. We could, therefore, be subject to more rigorous and costly disposal requirements in the future than we encounter today.

Superfund. The Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain persons with respect to the release of hazardous substances into the environment. These persons include the owner and operator of a site and any party that disposed of or arranged for the disposal of hazardous substances found at a site. CERCLA also authorizes the EPA, and in some cases, private parties, to undertake actions to clean up such hazardous substances, or to recover the costs of such actions from the responsible parties. In the course of business, we have generated and will continue to generate wastes that may fall within CERCLA’s definition of hazardous substances. We may also be an owner or operator of sites on which hazardous substances have been released. As a result, we may be responsible under CERCLA for all or part of the costs to clean up sites where such wastes have been disposed.

Oil Pollution Act. The federal Oil Pollution Act of 1990, or OPA, and resulting regulations impose a variety of obligations on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. The term “waters of the United States” has been broadly defined to include inland water bodies, including wetlands and intermittent streams. OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. We believe that we substantially comply with OPA and related federal regulations.

Clean Water Act. The Federal Water Pollution Control Act, or Clean Water Act, and resulting regulations, which are implemented through a system of permits, also govern the discharge of certain contaminants into waters of the United States. Sanctions for failure to comply strictly with the Clean Water Act are generally resolved by payment of fines and correction of any identified deficiencies. However, regulatory agencies could require us to cease operation of our marine vessels or offshore production facilities that are the source of water discharges. We believe that we substantially comply with the Clean Water Act and related federal and state regulations.

Clean Air Act. Our operations are subject to local, state and federal laws and regulations to control emissions from sources of air pollution. Payment of fines and correction of any identified deficiencies generally resolve penalties for failure to comply strictly with air regulations or permits. Regulatory agencies could also require us to cease operation of certain marine vessels or offshore production facilities that are air emission sources. We believe that we substantially comply with the emission standards under local, state, and federal laws and regulations.

Maritime Employees

Certain of our employees who perform services on offshore platforms and liftboats are covered by the provisions of the Jones Act, the Death on the High Seas Act and general maritime law. These laws operate to make the liability limits established under state workers’ compensation laws inapplicable to these employees. Instead, these employees or their representatives are permitted to pursue actions against us for damages for job related injuries, with generally no limitations on our potential liability.

Employees

As of February 28, 2005, we had approximately 3,350 employees. None of our employees is represented by a union or covered by a collective bargaining agreement. We believe that our relationship with our employees is good.

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Facilities

Our corporate headquarters are located on a 17-acre tract in Harvey, Louisiana, which we also use to support our well intervention, marine and rental operations. Our other principal operating facility is located on a 32-acre tract in Broussard, Louisiana, which we use to support our rental tools and well intervention group operations in the Gulf of Mexico. We support the operations conducted by our liftboats from a 3.5-acre maintenance and office facility in New Iberia, Louisiana 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, including a 7-acre office and training facility located in Houston, Texas. We have a total of 86 facilities located in Louisiana, Texas, Alabama, Oklahoma, Wyoming, Venezuela, Australia, Trinidad, Mexico, the North Sea, Eastern Canada, the Middle East and West Africa to support our operations. We believe that all of our leases are at competitive or market rates and do not anticipate any difficulty in leasing suitable additional space as may be needed or extending terms when our current leases expire.

Oil and Natural Gas Reserves

The following table presents our estimated net proved oil and natural gas reserves at December 31, 2004 and 2003 and estimated future net revenues and cash flows attributable thereto. We had no reserves prior to 2003. Our proved reserves at December 31, 2003 were estimated by us based on internal reports. Our proved reserves for 2004 were estimated by DeGolyer and MacNaughton, independent petroleum engineers.

                 
    As of December 31,  
    2004     2003  
Total estimated net proved reserves:
               
Oil (Mbbls)
    9,120       190  
Natural gas (Mmcf)
    29,380       3,224  
Total (Mboe) (1)
    14,017       727  
Net proved developed reserves (5):
               
Oil (Mbbls)
    7,731       64  
Natural gas (Mmcf)
    25,542       3,190  
Total (Mboe) (1)
    11,988       596  
Estimated future net revenues before income taxes (in thousands) (3)
  $ 285,437     $ 6,758  
Present value of estimated future net revenues before income taxes (in thousands) (2) (3)
  $ 221,226     $ 6,563  
Standardized measure of discounted future net cash flows (in thousands) (4)
  $ 136,507     $ 3,990  

(1) Barrel of oil equivalents (Boe) are determined using the ratio of 6 thousand cubic feet (Mcf) of natural gas to 1 barrel (Bbl) of oil or condensate. Mboe, Mbbls and Mmcf mean a thousand boe, a thousand Bbl and a million cubic feet, respectively.

(2) The present value of estimated future net revenues attributable to our reserves was prepared using constant prices, as of the calculation date, discounted at 10% per year on a pre-tax basis.

(3) The December 31, 2004 amount was estimated by DeGolyer and MacNaughton using a period-end crude New York Mercantile Exchange (NYMEX) price of $43.46 per Bbl for oil and a Henry Hub gas price of $6.19 per million British Thermal units for natural gas, and price differentials provided by us. The December 31, 2003 amount was estimated by us using a period end oil price of $32.55 per Bbl and $6.14 per Mcf for natural gas, with no change. Net revenues as they appear in the table are defined as gross revenue, less production taxes, operating expenses and capital costs.

(4) The standardized measure of discounted future net cash flows, calculated by us, represents the present value of future cash flows after income tax discounted at 10%.

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(5) Net proved developed non-producing reserves at December 31, 2004 were 3,903 Mbbls (42.8% of total net proved oil reserves) and 15,197 Mmcf (51.7% of total net proved gas reserves). Net proved undeveloped reserves as of December 31, 2004 were 1,390 Mbbls (15.2% of total net proved oil reserves) and 3,838 Mmcf (13.1% of total net proved gas reserves).

We filed no reserve estimates with any Federal authorities or agencies during 2004.

Our reserve information is prepared in accordance with guidelines established by the Securities and Exchange Commission, including using prices and costs determined on the date of the actual estimate, without considering hedge contracts in place at the end of the period, and a 10% discount rate to determine the present value of future net cash flow. There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control such as commodity pricing. Therefore, the foregoing reserve information represents only estimates, and is not intended to represent the current market value of our estimated oil and natural gas reserves. We believe that the following factors should be taken into account in reviewing our reserve information: (1) future costs and selling prices will probably differ from those required to be used in these calculations; (2) due to future market conditions and governmental regulations, actual rates of production achieved in future years may vary significantly from the rate of production assumed in the calculations; (3) selection of a 10% discount rate is arbitrary and may not be reasonable as a measure of the relative risk inherent in realizing future net oil and gas revenues; and (4) future net revenues may be subject to different rates of income taxation.

Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that can not be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers may vary. In addition, results of production subsequent to the date of an estimate may justify revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of oil and gas that are ultimately recovered. The meaningfulness of these estimates depends primarily on the accuracy of the assumptions upon which they were based. Except to the extent we acquire additional properties containing proved reserves, our proved reserves should decline as reserves are produced.

Productive Wells Summary

The following table presents our ownership at December 31, 2004, of productive oil and natural gas wells. Productive wells consist of producing wells and wells capable of production. Thirteen gross oil wells and two gross natural gas wells have dual completions. In the table, “gross” refers to the total wells in which we own an interest and “net” refers to the sum of fractional interests owned in gross wells.

                 
    Total  
    Productive Wells  
    Gross     Net  
Oil
    309.00       297.14  
Natural gas
    41.00       34.39  
 
           
Total
    350.00       331.53  
 
           

As of December 31, 2004, only approximately 180 of our gross wells were actually producing. Due to the maturity of our properties, a number of our productive wells are not able to produce on a regular basis or without incurring significant additional costs. Accordingly, they may never actually produce.

Acreage

The following table sets forth information as of December 31, 2004 relating to acreage held by us. Developed acreage is assigned to producing wells.

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    Gross     Net  
    Acreage     Acreage  
Developed
    143,971       121,528  
Undeveloped
    10,760       8,260  
 
           
Total
    154,731       129,788  
 
           

Leases covering 46% of our undeveloped net acreage will expire in 2005 and 54% will expire in 2006.

Drilling Activity

The following table shows our drilling activity for the years ended December 31, 2004 and 2003. We had no well ownership, and thus no drilling activity, in 2002. We did not drill any exploratory wells during the periods covered by the table. In the table, “gross” refers to the total wells in which we have a working interest and “net” refers to the gross wells multiplied by our working interest in these wells. Well activity refers to the number of wells completed during a fiscal year, regardless of when drilling first commenced. For this table, “completed” refers to the installation of permanent equipment for the production of oil and gas.

                                 
    2004     2003  
    Gross     Net (1)     Gross     Net (1)  
Development Wells:
                               
Productive
    3.00       0.06       0.00       0.00  
Non-productive
    0.00       0.00       0.00       0.00  
 
                       
Total
    3.00       0.06       0.00       0.00  
 
                       

(1) These wells were proposed and drilled under the supervision of our exploitation partner in an offshore lease in which we have only a 2% working interest.

Costs Incurred in Oil and Natural Gas Activities

The following table displays certain information regarding the costs incurred associated with finding, acquiring and developing our proved oil and natural gas reserves (in thousands). Our first property acquisition occurred in December 2003.

                 
    Years Ended December 31,  
    2004     2003  
Acquisition of properties — proved
  $ 81,356     $ 5,041  
Development costs
    4,707        
 
           
Costs incurred
    86,063       5,041  
 
           
Asset retirement liabilities incurred
    83,021       38,853  
Asset retirement revisions
    (1,535 )      
 
           
Total costs incurred
  $ 167,549     $ 43,894  
 
           

The asset retirement liability amounts incurred do not give any effect to our contractual right to receive amounts from third parties, which is approximately $38.7 million, when decommissioning operations are completed.

Capitalized costs for oil and gas producing activities consist of the following (in thousands):

                 
    2004     2003  
Proved properties
  $ 86,063     $ 5,041  
Accumulated depreciation, depletion and amortization
    (7,156 )     (131 )
 
           
 
  $ 78,907     $ 4,910  
 
           

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Intellectual Property

We use several patented items in our operations that we believe are important but are not indispensable to our operations. Although we anticipate seeking patent protection when possible, we rely to a greater extent on the technical expertise and know-how of our personnel to maintain our competitive position.

Other Information

We have our principal executive offices at 1105 Peters Road, Harvey, Louisiana. Our telephone number is (504) 362-4321. We also have a website at http://www.superiorenergy.com. Copies of the annual, quarterly and current reports we file with the SEC, and any amendments to those reports, are available on our website free of charge, soon after such reports are filed with or furnished to the SEC. The information posted on our website is not incorporated into this Annual Report on Form 10-K. Alternatively, you may access these reports at the SEC’s internet website: http://www.sec.gov/ .

Risk Factors

We are subject to the cyclical nature of the oil and gas industry.

Our business depends primarily on the level of activity by the oil and gas companies in the Gulf of Mexico and along the Gulf Coast. This level of activity has traditionally been volatile as a result of fluctuations in oil and gas prices and their uncertainty in the future. The purchases of the products and services we provide are, to a substantial extent, deferrable in the event oil and gas companies reduce capital expenditures. Therefore, the willingness of our customers to make expenditures is critical to our operations. The levels of such capital expenditures are influenced by:

  •   oil and gas prices and industry perceptions of future prices;
 
  •   the cost of exploring for, producing and delivering oil and gas;
 
  •   the ability of oil and gas companies to generate capital;
 
  •   the sale and expiration dates of offshore leases;
 
  •   the discovery rate of new oil and gas reserves; and
 
  •   local and international political and economic conditions.

Although activity levels in production and development sectors of the oil and gas industry are less immediately affected by changing prices and as a result, less volatile than the exploration sector, producers generally react to declining oil and gas prices by reducing expenditures. This has in the past and may in the future, adversely affect our business. We are unable to predict future oil and gas prices or the level of oil and gas industry activity. A prolonged low level of activity in the oil and gas industry will adversely affect the demand for our products and services and our financial condition 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:

  •   changes in competitive prices;
 
  •   fluctuations in the level of activity in major markets;
 
  •   an increased number of liftboats in the Gulf of Mexico;
 
  •   general economic conditions; and
 
  •   governmental regulation.

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.

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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.

We may not be able to acquire oil and gas properties to increase our asset utilization.

Our strategy to increase our asset utilization depends on our ability to find, acquire, manage and decommission mature Gulf of Mexico oil and gas properties. Factors that may hinder our ability to acquire these properties include competition, prevailing oil and natural gas prices and the number of properties for sale. Another factor that could hinder our ability to acquire oil and gas properties is our ability to assume additional decommissioning liabilities without posting bonds or providing other financial security to the U.S. Department of Interior, Minerals Management Service, or MMS, or the sellers of these properties, the cost of which may render our proposal unattractive to us or the sellers. In addition, our ability to assume obligations relating to plugging and abandonment liability is currently limited by the terms of our credit facility to the lesser of $160 million gross future value at any one time in the aggregate or the amount permitted by MMS. In certain instances, the sellers of these properties may have continuing obligations to us that are unsecured, and although we believe these arrangements represent minimal credit risk, we cannot assure you that any seller will not become a credit risk in the future. If we are unable to find and acquire properties meeting our criteria on acceptable terms to us, we will not be able to increase the utilization of our assets and services during seasonal downtime and when we have available equipment not being utilized by our traditional customer base. We cannot assure you that we will be able to locate and acquire such properties.

Estimates of our oil and gas reserves and potential liabilities relating to our oil and gas properties may be significantly incorrect.

We acquire mature oil and gas properties in the Gulf of Mexico on an “as is” basis and assume all plugging, abandonment, restoration and environmental liability with limited remedies for breaches of representations and warranties. In addition, we acquire these properties without obtaining bonds, other than as required by MMS to secure the plugging and abandonment obligations. Acquisitions of these properties require an assessment of a number of factors beyond our control, including estimates of recoverable reserves, future oil and gas prices, operating costs and potential environmental and plugging and abandonment liabilities. These assessments are complex and inherently imprecise, and, with respect to estimates of oil and gas reserves, require significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. In addition, since these properties are typically near the end of their economic lives, our operations may be more susceptible to equipment failure or mechanical problems. In connection with these assessments, we perform due diligence reviews that we believe are generally consistent with industry practices. However, our reviews may not reveal all existing or potential problems. In addition, our reviews may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We may not always discover structural, subsurface, environmental or other problems that may exist or arise.

Actual future production, cash flows, development expenditures, operating and abandonment expenses and quantities of recoverable oil and gas reserves may vary substantially from those estimated by us and any significant variance in these assumptions could materially affect the estimated quantity and value of our proved reserves. Therefore, the risk is that we may overestimate the value of economically recoverable reserves and/or underestimate the cost of plugging wells and abandoning production facilities. If costs of abandonment are materially greater or actual reserves are materially lower than our estimates, they could have an adverse effect on earnings.

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

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months. The seasonality of oil and gas industry activity as a whole in the Gulf Coast region also affects our operations and rentals and sales of equipment. Weather conditions generally result in higher activity in the spring, summer and fall months with the lowest activity in winter months. The rainy weather, tropical storms, hurricanes and other storms prevalent in the Gulf of Mexico and along the Gulf Coast during the year, such as Hurricane Ivan in September 2004, 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.

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. Although we did not have a single customer account for more than 10% of our total revenue in 2004, in 2003 and 2002, sales to a single customer accounted for approximately 11% and 12% of our total revenue, respectively, primarily in our well intervention and other oilfield service segments. Our inability to continue to perform services for a number of our large existing customers, if not offset by sales to new or other existing customers could have a material adverse effect on our business and operations.

The dangers inherent in our operations and the limits on insurance coverage could expose us to potentially significant liability costs and materially interfere with the performance of our operations.

Our operations are subject to numerous operating risks inherent in the oil and gas industry that could result in substantial losses. These risks include:

  •   fires;
 
  •   explosions, blowouts, and cratering;
 
  •   well blowouts;
 
  •   mechanical problems, including pipe failure;
 
  •   abnormally pressured formations; and
 
  •   environmental accidents, including oil spills, gas leaks or ruptures, uncontrollable flows of oil, gas, brine or well fluids, or other discharges of toxic gases or other pollutants.

Our liftboats are also subject to operating risks such as catastrophic marine disaster, adverse weather conditions, collisions and navigation errors.

The occurrence of these risks could result in substantial losses due to personal injury, loss of life, damage to or destruction of wells, production facilities or other property or equipment, or damages to the environment. In addition, certain of our employees who perform services on offshore platforms and vessels are covered by provisions of the Jones Act, the Death on the High Seas Act and general maritime law. These laws make the liability limits established by state workers’ compensation laws inapplicable to these employees and instead permit them or their representatives to pursue actions against us for damages for job-related injuries. In such actions, there is generally no limitation on our potential liability.

Any litigation arising from a catastrophic occurrence involving our services, equipment or oil and gas production operations could result in large claims for damages. The frequency and severity of such incidents affect our operating costs, insurability and relationships with customers, employees and regulators. Any increase in the frequency or severity of such incidents, or the general level of compensation awards with respect to such incidents, could affect our ability to obtain projects from oil and gas companies or insurance. We maintain several types of insurance to cover liabilities arising from our services, including onshore and offshore non-marine operations, as well as marine vessel operations. These policies include primary and excess umbrella liability policies with limits of $50 million dollars per occurrence. For our oil and gas operations, we also maintain control of well, operators extra

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expense and pollution liability coverage, to include our liabilities under the federal Oil Pollution Act of 1990, or OPA. Limits maintained for these operations are $35 million per occurrence for well control incidents, while the limit is $50 million per occurrence for non-well control events. We also maintain what we believe is prudent levels of property insurance on our physical assets, including marine vessels, offshore production facilities, and operating equipment. 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 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.

The occurrence of any of these risks could also subject us to clean-up obligations, regulatory investigation, penalties or suspension of operations. Further, our operations may be materially curtailed, delayed or canceled as a result of numerous factors, including:

  •   the presence of unanticipated pressure or irregularities in formations;
 
  •   equipment failures or accidents;
 
  •   weather conditions;
 
  •   compliance with governmental requirements; and
 
  •   shortages or delays in obtaining drilling rigs or in the delivery of equipment and services.

Oil and gas prices are volatile, and low prices could have a material adverse impact on our business.

Our revenues, profitability and future growth and the carrying value of our oil and gas properties depend substantially on the prices we realize for our production. Our realized prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital.

Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile in the future. Among the factors that can cause this volatility are:

  •   worldwide or regional demand for energy, which is affected by economic conditions;
 
  •   the domestic and foreign supply of oil and gas;
 
  •   weather conditions;
 
  •   domestic and foreign governmental regulations;
 
  •   political conditions in oil and gas producing regions;
 
  •   the ability of members of the Organization of Petroleum Exporting Countries to agree upon and maintain oil prices and production levels; and
 
  •   the price and availability of alternative fuel sources.

It is impossible to predict oil and gas price movements with certainty. Lower oil and gas prices may not only decrease our revenues on a per unit basis but also may reduce the amount of oil and gas that we can produce economically. A substantial or extended decline in oil or gas prices may materially and adversely affect our future business, financial condition, results of operations, liquidity and ability to finance planned capital expenditures. Further, oil prices and gas prices do not necessarily move together.

Our oil and gas revenues are subject to commodity price risk.

We are subject to market risk exposure in the pricing applicable to our oil and gas production. Considering the historical and continued volatility and uncertainty of prices received for oil and gas production, we have and will continue to enter into hedging arrangements to reduce our exposure to decreases in the prices of natural gas and oil.

Hedging arrangements expose us to risk of significant financial loss in some circumstances including circumstances where:

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  •   there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received;
 
  •   our production and/or sales of natural gas are less than expected;
 
  •   payments owed under derivative hedging contracts typically come due prior to receipt of the hedged month’s production revenue; and
 
  •   the other party to the hedging contract defaults on its contract obligations.

We cannot assure you that the hedging transactions we enter into will adequately protect us from declines in the prices of natural gas and oil. In addition, our hedging arrangements will limit the benefit we would receive from increases in the prices for natural gas and oil.

Factors beyond our control affect our ability to market oil and gas.

The availability of markets and the volatility of product prices are beyond our control and represent a significant risk. The marketability of our production depends upon the availability and capacity of gas gathering systems, pipelines and processing facilities. The unavailability or lack of capacity of these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Our ability to market oil and gas also depends on other factors beyond our control, including:

  •   the level of domestic production and imports of oil and gas;
 
  •   the proximity of gas production to gas pipelines;
 
  •   the availability of pipeline capacity;
 
  •   the demand for oil and natural gas by utilities and other end users;
 
  •   the availability of alternate fuel sources;
 
  •   state and federal regulation of oil and gas marketing; and
 
  •   federal regulation of gas sold or transported in interstate commerce.

If these factors were to change dramatically, our ability to market oil and gas could be adversely affected.

We are vulnerable to the potential difficulties associated with rapid expansion.

We have grown rapidly over the last several years through internal growth and acquisitions of other companies. We believe that our future success depends on our ability to manage the rapid growth that we have experienced and the demands from increased responsibility on our management personnel. The following factors could present difficulties to us:

  •   lack of sufficient executive-level personnel;
 
  •   increased administrative burden; and
 
  •   increased logistical problems common to large, expansive operations.

If we do not manage these potential difficulties successfully, our operating results could be adversely affected. The historical financial information incorporated 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

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addition, our management may not be able to effectively manage our increased size or operate a new line of business.

The nature of our industry subjects us to compliance with regulatory and environmental laws.

Our business is significantly affected by state and federal laws and other regulations relating to the oil and gas industry in general, and more specifically with respect to the environment, health and safety, waste management and the manufacture, storage, handling and transportation of hazardous wastes, and by changes in and the level of enforcement of such laws.

The production of oil and gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and plugging and abandonment and reports concerning operations.

Our oil and gas operations are conducted on federal leases that are administered by MMS and are required to comply with the regulations and orders promulgated by MMS under the Outer Continental Shelf Lands Act. MMS regulations also establish construction requirements for production facilities located on federal offshore leases and govern the plugging and abandonment of wells and the removal of production facilities from these leases. Under limited circumstances, MMS could require us to suspend or terminate our operations on a federal lease. MMS also establishes the basis for royalty payments due under federal oil and natural gas leases through regulations issued under applicable statutory authority.

The failure to comply with these rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability.

Our oil and gas operations are also subject to certain requirements under OPA. Under OPA and its implementing regulations, “responsible parties,” including owners and operators of certain vessels and offshore facilities, are strictly liable for damages resulting from spills of oil and other related substances in U.S. waters, subject to certain limitations. OPA also requires a responsible party to submit proof of its financial ability to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. Further, OPA imposes other requirements, such as the preparation of oil spill response plans. In the event of a substantial oil spill originating from one of our facilities, we could be required to expend potentially significant amounts of capital which could have a material adverse effect on our future operations and financial results.

We have potential environmental liabilities with respect to our offshore and onshore operations, including our environmental cleaning services. Certain environmental laws provide for joint and several liabilities for remediation of spills and releases of hazardous substances. These environmental statutes may impose liability without regard to negligence or fault. In addition, we may be subject to claims alleging personal injury or property damage as a result of alleged exposure to hazardous substances. We believe that our present operations substantially comply with applicable federal and state pollution control and environmental protection laws and regulations. We also believe that compliance with such laws has had no material adverse effect on our operations. However, such environmental laws are changed frequently. Sanctions for noncompliance may include revocation of permits, corrective action orders, administrative or civil penalties and criminal prosecution. We are unable to predict whether environmental laws will materially adversely affect our future operations and financial results.

Federal and state laws that require owners of non-producing wells to plug the well and remove all exposed piping and rigging before the well is permanently abandoned significantly affect the demand for our plug and abandonment services. A decrease in the level of enforcement of such laws and regulations in the future would adversely affect the demand for our services and products. In addition, demand for our services is affected by changing taxes, price controls and other laws and regulations relating to the oil and gas industry generally. The adoption of laws and regulations curtailing exploration and development drilling for oil and gas in our areas of operations for economic, environmental or other policy reasons could also adversely affect our operations by limiting demand for our services.

We are unable to predict the level of enforcement of existing laws and regulations, how such laws and regulations may be interpreted by enforcement agencies or court rulings, or whether additional laws and regulations will be

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adopted. We are also unable to predict the effect that any such events may have on us, our business, or our financial condition.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist efforts and other armed conflict involving the U.S. may adversely affect the U.S. and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

We will be subject to additional political, economic, and other uncertainties as we expand our international operations.

A key element of our business strategy is to continue our international expansion into international oil and gas producing areas such as Mexico, Trinidad, Venezuela, West Africa, the Middle East, Australia, Eastern Canada and the North Sea. Our international operations are subject to a number of risks inherent in any business operating in foreign countries including, but not limited to:

  •   political, social and economic instability;
 
  •   potential seizure or nationalization of assets;
 
  •   increased operating costs;
 
  •   modification or renegotiating of contracts;
 
  •   import-export quotas;
 
  •   currency fluctuations; and
 
  •   other forms of government regulation which are beyond our control.

Our operations have not yet been affected to any significant extent by such conditions or events, but as our international operations expand, the exposure to these risks will increase. We could, at any one time, have a significant amount of our revenues generated by operating activity in a particular country. Therefore, our results of operations could be susceptible to adverse events beyond our control that could occur in the particular country in which we are conducting such operations. We anticipate that our contracts to provide services internationally will generally provide for payment in U.S. dollars and that we will not make significant investments in foreign facilities. To the extent we make investments in foreign facilities or receive revenues in currencies other than U.S. dollars, the value of our assets and our income could be adversely affected by fluctuations in the value of local currencies.

Additionally, our competitiveness in international market areas may be adversely affected by regulations, including, but not limited to, regulations requiring:

  •   the awarding of contracts to local contractors;
 
  •   the employment of local citizens; and
 
  •   the establishment of foreign subsidiaries with significant ownership positions reserved by the foreign government for local citizens.

We cannot predict what types of the above events may occur.

We might be unable to employ a sufficient number of skilled workers.

The delivery of our products and services require personnel with specialized skills and experience. As a result, our ability to remain productive and profitable will depend upon our ability to employ and retain skilled workers. In addition, our ability to expand our operations depends in part on our ability to increase the size of our skilled labor force. The demand for skilled workers in the Gulf Coast region is high, and the supply is limited. In addition, although our employees are not covered by a collective bargaining agreement, the marine services industry has been targeted by maritime labor unions in an effort to organize Gulf of Mexico employees. A significant increase in the

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wages paid by competing employers or the unionization of our Gulf of Mexico employees could result in a reduction of our skilled labor force, increases in the wage rates that we must pay or both. If either of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.

Item 3. Legal Proceedings

We are involved in various legal and other proceedings that are incidental to the conduct of our business. We do not believe that any of these proceedings, if adversely determined, would have a material adverse affect on our financial condition, results of operations or cash flows.

Item 4. Submission of Matters to a Vote of Security Holders

None.

Item 4A. Executive Officers of Registrant

Terence E. Hall, age 59, has served as our Chairman of the Board and Chief Executive Officer and as a Director since December 1995. From December 1995 to November 2004, Mr. Hall also served as our President.

Kenneth L. Blanchard, age 55, has served as our President since November 2004, and as our Chief Operating Officer since June 2002. Mr. Blanchard also served as one of our Executive Vice Presidents from December 1995 to November 2004.

Robert S. Taylor, age 50, has served as our Chief Financial Officer since January 1996, as one of our Executive Vice Presidents since September 2004, and as our Treasurer since July 1999. He also served as one of our Vice Presidents from July 1999 to September 2004.

A. Patrick Bernard, age 47, has served as one of our Executive Vice Presidents since September 2004. He served as one of our Vice Presidents from June 2003 until September 2004. From July 1999 until June 2003, Mr. Bernard served as the Chief Financial Officer of our wholly-owned subsidiary International Snubbing Services, L.L.C. and its predecessor company.

L. Guy Cook, III, age 36, has served as one of our Executive Vice Presidents since September 2004. He has also served as a Vice President of our wholly owned subsidiary Superior Energy Services, L.L.C. and its predecessor company since August 2000. He served as our director of Investor Relations from April 1997 to February 2000 and was also responsible for integrating our acquisitions during that time.

James A. Holleman, age 47, has served as one of our Executive Vice Presidents since September 2004. He served as one of our Vice Presidents from July 1999 to September 2004. Since July 1999, Mr. Holleman has served as a Vice President of Superior Energy Services, L.L.C. From 1994 until July 1999, he served as the Chief Operating Officer of Cardinal Services, Inc., which we acquired in July 1999 and is the predecessor to Superior Energy Services, L.L.C.

Gregory L. Miller, age 47, has served as one of our Executive Vice Presidents since September 2004. He also serves as the President of our wholly-owned subsidiary SPN Resources, LLC, which position he has held since April 2003. From January 1991 to April 2003, Mr. Miller served as President and Chief Executive Officer of Optimal Energy, Inc.

Danny R. Young, age 49, has served as one of our Executive Vice Presidents since September 2004. He has also served as Vice President of Health, Safety and Environment and Corporate Services of Superior Energy Services, L.L.C. since January 2002. Prior to joining us, Mr. Young worked for 22 years at BP Amoco, with his most recent position there as manager of Health, Safety and Environmental.

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PART II

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

Common Stock Information

Our common stock trades on the New York Stock Exchange under the symbol “SPN.” The following table sets forth the high and low sales prices per share of common stock as reported for each fiscal quarter during the periods indicated.

                 
    High     Low  
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
  $ 10.95     $ 8.98  
Second Quarter
    11.30       8.65  
Third Quarter
    12.93       9.98  
Fourth Quarter
    15.73       11.95  

As of February 28, 2005, there were 77,554,214 shares of our common stock outstanding, which were held by 119 record holders.

Dividend Information

We do not plan to pay cash dividends on our common stock. We intend to retain all of the cash our business generates to meet our working capital requirements and fund future growth. In addition, our bank credit facility prevents us from paying dividends or making other distributions to our stockholders.

Equity Compensation Plan Information

Information required by this item with respect to compensation plans under which our equity securities are authorized for issuance will be contained in our definitive proxy statement to be filed pursuant to Regulation 14A and is incorporated herein by reference.

Purchases of Equity Securities

On September 22, 2004, our Board of Directors approved the repurchase of 9,696,627 shares of our common stock from First Reserve Fund VII, Limited Partnership and First Reserve Fund VIII, L.P., pursuant to a private transaction. This transaction, which was publicly announced by us, was consummated on October 19, 2004. The purchase price paid by us to the First Reserve funds was $11.70 per share, for a total aggregate purchase price of approximately $113.4 million.

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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 Operations” and our consolidated financial statements included elsewhere in this Annual Report. The financial data is in thousands, except per share amounts.

                                         
    Years Ended December 31,  
    2004     2003     2002     2001     2000  
Revenues
  $ 564,339 (1)   $ 500,625     $ 443,147     $ 449,042 (2)   $ 257,502 (3)
Income from operations
    76,289       67,343       57,021       104,953       43,359  
Income before cumulative effect of change in accounting principle
    35,852       30,514       21,886       51,187       18,324 (4)
Cumulative effect of change in accounting principle, net
                      2,589 (5)      
Net income
    35,852       30,514       21,886       53,776       18,324  
Net income before cumulative effect of change in accounting principle per share:
                                       
Basic
    0.48       0.41       0.30       0.74       0.28  
Diluted
    0.47       0.41       0.30       0.73       0.28  
Net income per share:
                                       
Basic
    0.48       0.41       0.30       0.78       0.28  
Diluted
    0.47       0.41       0.30       0.77       0.28  
Total assets
    1,003,913       832,863       727,620       665,520       430,676  
Long-term debt, less current portion
    244,906       255,516       256,334       269,633       146,393  
Decommissioning liabilities, less current portion
    90,430       18,756                    
Stockholders’ equity
    433,879       368,129       335,342       269,576       206,247  

(1)   In the year ended December 31, 2004, our subsidiary, SPN Resources, LLC, acquired additional oil and gas properties through the acquisition of interests in 19 offshore Gulf of Mexico leases. Under the terms of these transactions, we paid approximately $10.7 million (net of approximately $5.0 million cash received), acquired the properties and assumed the related decommissioning liabilities.
 
(2)   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.
 
(3)   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.
 
(4)   Income before cumulative effect of change in accounting principle has been restated for 2000 to include losses due to a refinance of our indebtedness of $1.6 million (net of a $1.0 million income tax benefit). 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.

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(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 on Form 10-K. The following information contains forward-looking statements, which are subject to risks and uncertainties. Should one or more of these risks or uncertainties materialize, our actual results may differ from those expressed or implied by the forward-looking statements. See “Forward-Looking Statements” at the beginning of this Annual Report on Form 10-K.

Executive Summary

We are a leading provider of specialized oilfield services and equipment focused on serving the production-related needs of oil and gas companies primarily in the Gulf of Mexico and the drilling-related needs of oil and gas companies in the Gulf of Mexico and select international market areas. We also own and operate, through our subsidiary SPN Resources, LLC, mature oil and gas properties in the Gulf of Mexico. Our business is organized into five segments consisting of well intervention services, marine services, rental tools, other oilfield services and oil and gas operations.

The oil and gas industry remains highly cyclical and seasonal. Activity levels in our four service and rental segments are driven primarily by traditional energy indicators, which include current and expected future commodity prices, drilling rig count in the Gulf of Mexico for services and worldwide for rental tools, oil and gas production levels, and customers’ capital spending allocated for drilling and production, particularly in the Gulf of Mexico.

In 2004, activity levels increased across all of our segments due to:

  •   increased demand as a result of better market conditions;
 
  •   the acquisition of several mature oil and gas properties which yielded higher oil and gas production and utilization for our services and liftboats;
 
  •   geographic expansion, primarily in the rental tools segment; and
 
  •   further market acceptance of our bundled services strategy which led to additional higher margin, production-related projects.

The acquisition of several mature Gulf of Mexico properties resulted in oil and gas production of approximately 918,000 barrels of oil equivalent Boe, net of royalties, in 2004 as compared to approximately 16,000 Boe in 2003. We incurred significant production downtime from mid-September 2004 until late December 2004 as a result of damage caused by Hurricane Ivan.

The acquisition of mature properties increased the utilization of our assets by providing us with additional decommissioning opportunities. We use our production-related assets to enhance, maintain and extend existing production and, at the end of a property’s economic life, to plug and decommission wells. Because we own and operate the properties, we are able to control when these services are provided and do so in a manner that employs our assets during seasonal downtime and at times we have available assets not otherwise being utilized. Work on our own properties accounted for 14% of the utilization of our well services crews within our well intervention segment for 2004, and 29% and 21% of their utilization for the first and fourth quarters of 2004, respectively.

Another factor impacting our growth in 2004 was our geographic expansion. We now have domestic rental tool operations in Louisiana, Oklahoma, Texas and Wyoming, and international rental tool operations in Venezuela, Trinidad, Mexico, Eastern Canada, the North Sea, the Middle East and West Africa. We also successfully capped several wells in Egypt as part of an ongoing well control project. International revenue in 2004 was a record $87.6 million, a 54% increase from the $56.7 million of international revenue we recorded in 2003.

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Finally, in 2004, we performed more bundled services projects on producing wells than we have in past years. Historically, our bundled services were employed on retiring wells following the end of their economic lives. We believe this is due to the use of our bundled services on our own producing wells, as well as a result of improving market conditions and further awareness of our bundled services offering.

We believe we are well positioned to capitalize on one of the most prevalent trends impacting our core shallow water Gulf of Mexico market — the divestment of properties by larger energy producers. The continued maturation of the market has led larger energy producers to sell assets in search of higher returning investments in the deepwater Gulf of Mexico and other developing markets worldwide. As a result, small energy producers are substantially increasing their investment and presence on the Gulf of Mexico Outer Continental Shelf. Our bundled strategy attempts to address these market dynamics and leverage the significant asset base dedicated to our core market. In addition, as large energy producers continue to divest, we believe our financial flexibility and operational experience make us a likely candidate to continue acquiring additional mature producing properties.

Well Intervention Segment

The well intervention segment consists of specialized downhole services, which are both labor and equipment intensive. While our gross margin percentage tends to be fairly consistent, special projects such as well control can directly increase the gross margin percentage.

Revenue and operating income increased each quarter during 2004 as demand steadily improved throughout the year. In 2004, we benefited from removing and decommissioning our offshore properties. In addition, our coiled tubing, mechanical wireline, plug and abandonment and well control operations grew from 2003 levels. The mechanical wireline operations posted record revenues and operating income in 2004. Our well control operations were involved in a major well control project during the fourth quarter.

Marine Segment

Liftboat operations have relatively high operating leverage, meaning that operating costs are fairly fixed and, therefore, gross margin percentages vary significantly from quarter-to-quarter and year-to-year based on changes in dayrates and utilization levels.

In 2004, liftboat days worked increased almost 2% and the average dayrate for our liftboat fleet was virtually unchanged as compared to 2003. However, the last half of 2004 was stronger than the first half of the year as liftboat days worked were about 5% higher in the third and fourth quarters as compared to the first and second quarters. In addition, the average fleet dayrate was 20% higher during the last six months of the year as compared to the first six months.

Rental Tools Segment

In 2004, our rental tools segment continued to grow through geographic expansion. New locations in Oklahoma, Texas and Wyoming yielded higher revenue and operating income in on-site accommodations, and stabilization and downhole tubulars businesses. Our August 2003 acquisition of Premier Oilfield Services resulted in increased rentals of specialty drill pipe and handling tools in the North Sea, Middle East and West Africa. In addition, we increased rentals of drill pipe, stabilizers and downhole tubulars and other related accessories in Trinidad and Mexico.

Revenue and operating income grew in the first and second quarters before Hurricane Ivan shut down several deepwater Gulf of Mexico projects in the third quarter. As a result, rentals in this market fell sharply and began to resume toward the end of the year. The segment’s gross margin percentage fell slightly as higher margin drill pipe rentals decreased in the third and fourth quarters.

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Other Oilfield Services Segment

More than half of this segment’s revenues are derived from our offshore platform and property management business, a labor-intensive business with low margins. Activity for this business increased as the group managed more properties from traditional customers and added properties we acquired in 2004. Environmental services, such as dockside vessel and tank cleaning and non-hazardous oilfield waste treatment, comprise most of the other revenue and operating income in this segment. The increase in the Gulf of Mexico drilling rig count helped increase activity for our environmental services. The segment’s gross margin percentage in 2004 was unchanged from 2003.

Oil and Gas Segment

In December 2003, we began our oil and gas production and sales business. Through our subsidiary SPN Resources, LLC, we acquire, manage and decommission mature properties in the shallow waters of the Gulf of Mexico. As of December 31, 2004, we had interests in 35 offshore blocks containing 64 structures and 350 productive wells, of which approximately 180 were producing.

Following our acquisition of these properties, SPN Resources will produce and sell the remaining economic oil and gas reserves of these properties. The lease operating expenses for these types of mature properties are typically higher than other properties because of the amount of well intervention service work required to enhance, maintain and extend production. The gross operating margin is also a function of oil and gas prices.

The main objective of this new business segment is to provide additional opportunities for our well intervention services and our platform management businesses. We intend to increase the utilization of our well intervention services by deploying these services on our own properties during periods of downtime.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Note 1 to our consolidated financial statements contains a description of the accounting policies used in the preparation of our financial statements. We evaluate our estimates on an ongoing basis, including those related to long-lived assets and goodwill, income taxes, allowance for doubtful accounts, self-insurance and oil and gas properties. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances. Actual amounts could differ significantly from these estimates under different assumptions and conditions.

We define a critical accounting policy or estimate as one that is both important to the portrayal of our financial condition and results of operations and requires us to make difficult, subjective or complex judgments or estimates about matters that are uncertain. We believe that the following are the critical accounting policies and estimates used in the preparation of our consolidated financial statements. In addition, there are other items within our consolidated financial statements that require estimates but are not deemed critical as defined in this paragraph.

Long-Lived Assets. We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of any such asset may not be recoverable. We record impairment losses on long-lived assets, including oil and gas properties, used in operations when the estimated cash flows to be generated by those assets are less than the carrying amount of those items. Our cash flow estimates are based upon, among other things, historical results adjusted to reflect our best estimate of future market rates, utilization levels, operating performance, and with respect to our oil and gas properties, future oil and natural gas sales prices, an estimate of the ultimate amount of recoverable oil and natural gas reserves that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas and other factors. Our estimates of cash flows may differ from actual cash flows due to, among other things, changes in economic conditions or changes in an 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

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on industry trends and reference to market transactions and is subject to variability. The oil and gas industry is cyclical and our estimates of the period over which future cash flows will be generated, as well as the predictability of these cash flows, can have significant impact on the carrying value of these assets and, in periods of prolonged down cycles, may result in impairment charges.

Goodwill. In assessing the recoverability of goodwill, we must make assumptions regarding estimated future cash flows and other factors to determine the fair value of the respective assets. If these estimates or their related assumptions adversely change in the future, we may be required to record material impairment charges for these assets not previously recorded. We test goodwill for impairment in accordance with Statement of Financial Accounting Standards No. 142 (FAS No. 142), “Goodwill and Other Intangible Assets.” FAS No. 142 requires that goodwill as well as other intangible assets with indefinite lives no longer be amortized, but instead tested annually for impairment. 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. We also have an actuary review our estimates for leases related to workers’ compensation and group medical on an annual basis. While we believe these estimates are reasonable based on the information available, our financial results could be impacted if litigation trends, claims settlement patterns, health care costs and future inflation rates are different from our estimates. Although we believe adequate reserves have been provided for expected liabilities arising from our self-insured obligations, and we believe that we maintain adequate reinsurance coverage, we cannot assure that such coverage will adequately protect us against liability from all potential consequences.

Oil and Gas Properties. One of our subsidiaries, SPN Resources, LLC, acquires mature oil and gas properties and assumes the related well abandonment and decommissioning liabilities. We follow the successful efforts method of accounting for our investment in oil and natural gas properties. Under the successful efforts method, the costs of successful exploratory wells and leases containing productive reserves are capitalized. Costs incurred to drill and equip developmental wells, including unsuccessful development wells are capitalized. Other costs such as geological and geophysical costs and the drilling costs of unsuccessful exploratory wells are expensed. SPN Resources’ property purchases are recorded at the value exchanged at closing, combined with an estimate of its

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proportionate share of the decommissioning liability assumed in the purchase. All capitalized costs are accumulated and recorded separately for each field and allocated to leasehold costs and well costs. Leasehold costs are depleted on a units-of-production basis based on the estimated remaining equivalent proved oil and gas reserves of each field. Well costs are depleted on a units-of-production basis based on the estimated remaining equivalent proved developed oil and gas reserves of each field.

We estimate the third party market value (including an estimated profit) to plug and abandon wells, abandon the pipelines, decommission and remove the platforms and clear the sites, and use that estimate to record our proportionate share of the decommissioning liability. In estimating the decommissioning liabilities, we perform detailed estimating procedures, analysis and engineering studies. Whenever practical, we will utilize the services of our subsidiaries to perform well abandonment and decommissioning work. When these services are performed by our subsidiaries, all recorded intercompany revenues and expenses are eliminated in the consolidated financial statements. The recorded decommissioning liability associated with a specific property is fully extinguished when the property is completely abandoned. The liability is first reduced by all cash expenses incurred to abandon and decommission the property. If the liability exceeds (or is less than) our out-of-pocket costs 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.

Oil and gas properties are assessed for impairment in value on a field-by-field basis whenever indicators become evident. We use our current estimate of future revenues and operating expenses to test the capitalized costs for impairment. In the event net undiscounted cash flows are less than the carrying value, an impairment loss is recorded based on the present value of expected future net cash flows over the economic lives of the reserves.

Proved Reserve Estimates. Our reserve information is prepared by independent reserve engineers in accordance with guidelines established by the Securities and Exchange Commission and generally accepted accounting principles. There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control such as commodity pricing. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that can not be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. In accordance with the Securities and Exchange Commission’s guidelines, we use prices and costs determined on the date of the actual estimate and a 10% discount rate to determine the present value of future net cash flow. Actual prices and costs may vary significantly, and the discount rate may or may not be appropriate based on outside economic conditions.

Derivative Instruments and Hedging Activities. We enter into hedging transactions for our oil production to reduce exposure to the fluctuations in oil prices. Our hedging transactions to date have consisted of financially-settled crude oil swaps and zero-cost collars with a major financial institution. We may in the future enter into these and other types of hedging arrangements to reduce our exposure to fluctuations in the market prices of oil and natural gas. Under the provisions of Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” we are required to record our derivative instruments at fair market value as either assets or liabilities in our consolidated balance sheet. The fair market value is an estimate based on future commodity prices available at the time of the calculation. The fair market value could differ from actual settlements if the other party to the contract defaults on its obligations or there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.

Comparison of the Results of Operations for the Years Ended December 31, 2004 and 2003

For the year ended December 31, 2004, our revenues were $564.3 million resulting in net income of $35.9 million or $0.47 diluted earnings per share. For the year ended December 31, 2003, revenues were $500.6 million and net income was $30.5 million which includes $2.8 million of pre-tax other income due to the gain from insurance proceeds; diluted earnings per share was $0.41 for the same period. We experienced higher revenues from our rental tools and well intervention segments. We also benefited from oil and gas production following our initial acquisition of properties in the Gulf of Mexico in December 2003.

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The following table compares our operating results for the years ended December 31, 2004 and 2003. Gross margin is calculated by subtracting cost of services from revenue for each of our five business segments. Oil and gas eliminations represent products and services provided to the oil and gas segment by the Company’s four other segments.

                                                                 
    Revenue     Gross Margin  
    2004     2003     Change     2004     %     2003     %     Change  
Well Intervention
  $ 211,820     $ 187,271     $ 24,549     $ 89,755       42 %   $ 75,941       41 %   $ 13,814  
Rental Tools
    170,064       141,362       28,702       112,711       66 %     95,243       67 %     17,468  
Marine
    69,808       70,370       (562 )     20,227       29 %     20,056       29 %     171  
Other Oilfield Services
    83,870       100,881       (17,011 )     16,077       19 %     19,368       19 %     (3,291 )
Oil and Gas
    37,008       741       36,267       15,461       42 %     410       55 %     15,051  
Less: Oil and Gas Elim.
    (8,231 )           (8,231 )                              
 
                                   
Total
  $ 564,339     $ 500,625     $ 63,714     $ 254,231       45 %   $ 211,018       42 %   $ 43,213  
 
                                   

The following discussion analyzes our operating results on a segment basis.

Well Intervention Segment

Revenue for our well intervention segment was $211.8 million for the year ended December 31, 2004, as compared to $187.3 million for the same period in 2003. This segment’s gross margin percentage increased to 42% in the year ended December 31, 2004 from 41% in 2003. We experienced increased demand for almost all of our services, and we also benefited by completing various decommissioning projects on our oil and gas properties. These increases in demand and decommissioning projects contributed to the improvement in the segment’s gross margin percentage.

Rental Tools Segment

Revenue for our rental tools segment for the year ended December 31, 2004 was $170.1 million, a 20% increase over 2003. The increase in this segment’s revenue was primarily due to an increased demand for our expanded inventory of downhole rental tool equipment and our continued international expansion, due primarily to the August 2003 acquisition of Premier Oilfield Services. In addition, we benefited from increased bolting, torque and on-site machining work and increased rentals of stabilizers and housing units. The gross margin percentage declined slightly to 66% in the year ended December 31, 2004 from 67% in of 2003 due primarily to a change in the mix of our rental revenue.

Marine Segment

Our marine segment revenue for the year ended December 31, 2004 slightly decreased 1% from 2003 to $69.8 million. The gross margin percentage for the year ended December 31, 2004 remained unchanged at 29%. The fleet’s average dayrate decreased slightly to $6,295 in the year ended December 31, 2004 from $6,306 in 2003, but average utilization increased to 72% for the year ended December 31, 2004 from 66% in 2003. Average fleet dayrates entering 2004 were significantly less than the same period a year ago due to lower demand for liftboats. As liftboat utilization increased throughout the year, we began to experience higher rates, particularly in the third and fourth quarters.

Other Oilfield Services Segment

Other oilfield services revenue for the year ended December 31, 2004 was $83.9 million, a 17% decrease over the $100.9 million in revenue for 2003. The lower revenue is primarily attributable to the sale of our construction and fabrication assets in August 2003, which had revenue of approximately $19.0 million in 2003. The gross margin percentage remained unchanged at 19% in 2004 and 2003. The decrease in revenue resulted in a $2.6 million operating loss for this segment in 2004.

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Oil and Gas Segment

Oil and gas revenues were $37.0 million and the gross margin percentage was 42% for the year ended December 31, 2004, compared to revenues of $0.7 million and gross margin percentage of 55% for the year ended December 31, 2003. The increase in revenue is due to the fact that our oil and gas segment began in December 2003 and has benefited from the South Pass 60 acquisition completed in July 2004. The segment was negatively impacted by Hurricane Ivan which shut-in or curtailed production from the South Pass 60 field beginning in mid-September 2004 through late December 2004.

Depreciation, Depletion, Amortization and Accretion

Depreciation, depletion, amortization and accretion increased to $67.3 million in the year ended December 31, 2004 from $48.9 million in 2003. The increase is primarily a result of depletion and accretion related to our oil and gas properties. The increase is also the result of our acquisition of Premier Oilfield Services in August 2003 and capital expenditures during 2003 and 2004.

General and Administrative

General and administrative expenses increased to $110.6 million for the year ended December 31, 2004 from $94.8 million in 2003. The increase is primarily the result of our acquisitions, internal growth and international expansion.

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 table compares our operating results for the years ended December 31, 2003 and 2002. Gross margin is calculated by subtracting cost of services from revenue for each of our five business segments.

                                                                 
    Revenue     Gross Margin  
    2003     2002     Change     2003     %     2002     %     Change  
Well Intervention
  $ 187,271     $ 148,670     $ 38,601     $ 75,941       41 %   $ 55,196       37 %   $ 20,745  
Rental Tools
    141,362       124,085       17,277       95,243       67 %     85,710       69 %     9,533  
Marine
    70,370       67,884       2,486       20,056       29 %     23,236       34 %     (3,180 )
Other Oilfield Services
    100,881       102,508       (1,627 )     19,368       19 %     20,671       20 %     (1,303 )
Oil and Gas
    741             741       410       55 %                 410  
 
                                   
Total
  $ 500,625     $ 443,147     $ 57,478     $ 211,018       42 %   $ 184,813       42 %   $ 26,205  
 
                                   

The following discussion analyzes our operating results on a segment basis.

Well Intervention Segment

Revenue for our well intervention segment was $187.3 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.

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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.

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.

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.

Oil and Gas Segment

Our oil and gas production did not begin until December 2003, following our initial acquisition of properties in the Gulf of Mexico during that same month. Oil and gas revenues generated during that month were $0.7 million and the gross margin percentage was 55%.

Depreciation, Depletion, Amortization and Accretion

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.

Liquidity and Capital Resources

In the year ended December 31, 2004, we generated net cash from operating activities of $91.3 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 $15.3 million at December 31, 2004 compared to $19.8 million at December 31, 2003.

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We made $74.1 million of capital expenditures during the year ended December 31, 2004, of which approximately $49.9 million was used to expand and maintain our rental tool equipment inventory. We also made $19.6 million of capital expenditures to expand and maintain the asset base of our well intervention, marine, other oilfield services and oil and gas segments and $4.6 million on construction and improvements to our facilities. Cash generated from our operations and availability under our revolving credit facility will provide sufficient funds for our identified capital projects.

We paid $24.4 million during the year ended December 31, 2004 as a result of our business acquisitions, which includes additional consideration for prior acquisitions of $21.6 million, of which $10.7 million was earned, capitalized and accrued during 2003, and $10.9 million was earned, capitalized and accrued in 2004. We capitalized and accrued additional consideration of $5.3 million for one prior acquisition, which was paid in the first quarter of 2005.

During 2004, our subsidiary, SPN Resources, LLC, acquired additional oil and gas properties through the acquisition of interests in 19 offshore leases. Under the terms of the transactions, we paid approximately $10.7 million (net of approximately $5.0 million cash received), acquired the properties and assumed the related decommissioning liabilities.

We have a bank credit facility consisting of term loans in an aggregate amount of $38.5 million outstanding at December 31, 2004 and a revolving credit facility of $75 million, none of which was outstanding at December 31, 2004. We amended the credit facility effective June 30, 2004 to extend the maturity date of one of the term loans. As of February 28, 2005, these balances were unchanged and the weighted average interest rate on amounts outstanding under the credit facility was 4.9% 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 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, incur additional indebtedness or assume additional decommissioning liabilities.

We have $18.2 million outstanding at December 31, 2004 in U. S. Government guaranteed long-term financing under Title XI of the Merchant Marine Act of 1936, which is administered by the Maritime Administration (MARAD), for two 245-foot class liftboats. This debt bears an interest rate of 6.45% per annum and is payable in equal semi-annual installments of $405,000 on every June 3rd and December 3rd through June 3, 2027. Our obligations are secured by mortgages on the two liftboats. This MARAD financing also requires that we comply with certain covenants and restrictions, including the maintenance of minimum net worth and debt-to-equity requirements.

We also have outstanding $200 million of 8 7/8% senior notes due 2011. The indenture governing the senior notes requires semi-annual interest payments on every May 15th and November 15th through the maturity date of May 15, 2011. 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 $180 million at December 31, 2004. The indenture also contains covenants that restrict our ability to create certain liens, sell assets or enter into certain mergers or acquisitions.

The following table summarizes our contractual cash obligations and commercial commitments at December 31, 2004 (amounts in thousands) for our long-term debt (including interest payments), decommissioning liabilities and operating leases. The interest payments on our variable debt were estimated using the rates in effect at December 31, 2004. The decommissioning liability amounts do not give any effect to our contractual right to receive amounts from third parties, which is approximately $38.7 million, when decommissioning operations are performed. We do not have any other material obligations or commitments.

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Description   2005     2006     2007     2008     2009     Thereafter  
 
Long-term debt, including estimated interest payments
  $ 32,381     $ 31,792     $ 31,211     $ 25,164     $ 19,513     $ 249,009  
Decommissioning liabilities
    23,588       12,693       10,907       4,574       5,107       57,149  
Operating leases
    5,047       3,887       2,639       1,415       517       13,735  
 
   
Total
  $ 61,016     $ 48,372     $ 44,757     $ 31,153     $ 25,137     $ 319,893  
 
   

We have no off-balance sheet arrangements other than our potential additional consideration that may be payable as a result of our acquisitions. 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 that may be payable by us for completed acquisitions is approximately $2.8 million. These amounts are not classified as liabilities under generally accepted accounting principles and are not reflected in our financial statements until the amounts are fixed and determinable. When amounts are determined, they are capitalized as part of the purchase price of the related acquisition. We do not have any other financing arrangements that are not required under generally accepted accounting principles to be reflected in our financial statements.

We have identified capital expenditure projects that will require up to approximately $90 million in 2005, 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.

Hedging Activities

We enter into hedging transactions with major financial institutions to secure a commodity price for a portion of our future production and to reduce our exposure to fluctuations in the price of oil. We do not enter into hedging transactions for trading purposes. Crude oil hedges are settled based on the average of the reported settlement prices for West Texas Intermediate crude on the New York Mercantile Exchange (NYMEX) for each month. We had no natural gas hedges as of December 31, 2004. We use financially-settled crude oil swaps and zero-cost collars that provide floor and ceiling prices with varying upside price participation. Our swaps and zero-cost collars are designated and accounted for as cash flow hedges.

With a financially-settled swap, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the hedged price for the transaction, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. With a zero-cost collar, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price of the collar, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar. We recognize the fair value of all derivative instruments as assets or liabilities on the balance sheet. Changes in the fair value of cash flow hedges are recognized, to the extent the hedge is effective, in other comprehensive income until the hedged item is recognized in earnings. For the year ended December 31, 2004, hedging settlement payments reduced oil revenues by $1.6 million dollars, and we recognized no gains or losses due to hedge ineffectiveness.

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We had the following hedging contracts as of December 31, 2004:

                                 
Crude Oil Positions  
    Instrument     Strike     Volume (Bbls)        
Remaining Contract Term   Type     Price (Bbl)     Daily     Total (Bbls)  
01/05 - 8/06
  Swap   $ 39.45       1,000 - 1,225       683,801  
01/05 - 8/06
  Collar   $ 35.00/$45.60       1,000 - 1,225       683,801  

Recently Issued Accounting Pronouncements

During 2004, the Financial Accounting Standards Board issued the following standards, which we intend to adopt as required:

  •   Statement of Financial Accounting Standards No. 151 (FAS No. 151), “Inventory Costs.”
 
  •   Statement of Financial Accounting Standards No. 152 (FAS No. 152), “Accounting for Real Estate Time-Sharing Transactions — An Amendment of FASB Statements No. 66 and 67.”
 
  •   Statement of Financial Accounting Standards No. 153 (FAS No. 153), “Exchanges of Nonmonetary Assets — An Amendment of APB Opinion No. 29.”
 
  •   Statement of Financial Accounting Standards No. 123 (FAS No. 123R), “Accounting for Stock Based Compensation.”

For detailed information regarding any of these pronouncements and the impact thereof on our business, see note 15 to our consolidated financial statements.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to market risks associated with foreign currency fluctuations and changes in interest rates. A discussion of our market risk exposure in financial instruments follows.

Foreign Currency Exchange Rates

Because we operate in a number of countries throughout the world, we conduct a portion of our business in currencies other than the U.S. dollar. The functional currency for most of our international operations is the U.S. dollar, but a portion of the revenues from our foreign operations is paid in foreign currencies. The effects of foreign currency fluctuations are partly mitigated because local expenses of such foreign operations are also generally denominated in the same currency. We continually monitor the currency exchange risks associated with all contracts not denominated in the U.S. dollar. Any gains or losses associated with such fluctuations have not been material.

We do not hold any foreign currency exchange forward contracts and/or currency options. We have made 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 entered into 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.

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Interest Rates

At December 31, 2004, $38.5 million of our long-term debt had variable interest rates. Based on debt outstanding at December 31, 2004, a 10% increase in variable interest rates would increase our interest expense in the year 2004 by approximately $188,000, while a 10% decrease would decrease our interest expense by approximately $188,000.

Commodity Price Risk

Our revenue, profitability and future rate of growth partially depends upon the market prices of oil and natural gas. Lower prices may also reduce the amount of oil and gas that can economically be produced.

We use derivative commodity instruments to manage commodity price risks associated with future oil and natural gas production. As of December 31, 2004, we had the following contracts in place:

                                 
Crude Oil Positions  
    Instrument     Strike     Volume (Bbls)        
Remaining Contract Term   Type     Price (Bbl)     Daily     Total (Bbls)  
01/05 - 8/06
  Swap   $ 39.45       1,000 - 1,225       683,801  
01/05 - 8/06
  Collar   $ 35.00/$45.60       1,000 - 1,225       683,801  

Our hedged volume as of December 31, 2004 was approximately 47% of our estimated production from proved reserves for the balance of the terms of the contracts. Had these contracts been terminated at December 31, 2004, the estimated loss would have been $1.7 million net of taxes.

We used a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of crude oil would have on the fair value of its existing derivative instruments. Based on the derivative instruments outstanding at December 31, 2004, a 10% increase in the underlying commodity price, increased the net estimated loss associated with the commodity derivative instrument by $2.7 million.

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Item 8. Financial Statements and Supplementary Data

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over our financial reporting, and for performing an assessment of the effectiveness of internal control over our financial reporting as of December 31, 2004. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our system of internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the financial statements.

Our management, including our principal executive officer and principal financial officer, performed an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004 based upon criteria in “Internal Control — Integrated Framework,” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment under the criteria in “Internal Control — Integrated Framework,” our management determined that our internal control over financial reporting was effective as of December 31, 2004.

Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which appears herein.

     
/s/ Terence E. Hall
  /s/ Robert S. Taylor
Terence E. Hall   Robert S. Taylor
Chairman of the Board and   Chief Financial Officer,
Chief Executive Officer   Executive Vice President and Treasurer

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Independent Registered Public Accounting Firm 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, 2004 and 2003, 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, 2004. 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, 2004, 2003 and 2002. 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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Superior Energy Services, Inc. and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Superior Energy Services, Inc.’s internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 11, 2005 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

KPMG LLP

New Orleans, Louisiana
March 11, 2005

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Independent Registered Public Accounting Firm Report

The Board of Directors and Stockholders
Superior Energy Services, Inc.:

We have audited management’s assessment, included in the accompanying “Management’s Report on Internal Control over Financial Reporting,” that Superior Energy Services, Inc. maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Superior Energy Services, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that Superior Energy Services, Inc. maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, Superior Energy Services, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

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We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Superior Energy Services, Inc. and subsidiaries as of December 31, 2004 and 2003, 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, 2004. 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, 2004, 2003 and 2002. Our report dated March 11, 2005 expressed an unqualified opinion on those consolidated financial statements and schedule.

KPMG, LLP

New Orleans, Louisiana
March 11, 2005

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
December 31, 2004 and 2003
(in thousands, except share data)

                 
    2004     2003  
ASSETS
               
 
               
Current assets:
               
Cash and cash equivalents
  $ 15,281     $ 19,794  
Accounts receivable — net of allowance for doubtful accounts of $8,364 in 2004 and $6,280 in 2003
    156,235       112,775  
Income taxes receivable
    2,694        
Current portion of notes receivable
    9,611       19,212  
Prepaid insurance and other
    28,203       14,059  
 
           
Total current assets
    212,024       165,840  
 
           
Property, plant and equipment — net
    515,151       427,360  
Goodwill — net
    226,593       204,727  
Notes receivable
    29,131       15,145  
Investments in affiliates
    14,496       13,224  
Other assets — net
    6,518       6,567  
 
           
Total assets
  $ 1,003,913     $ 832,863  
 
           
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
 
               
Current liabilities:
               
Accounts payable
  $ 36,496     $ 20,817  
Accrued expenses
    56,796       48,949  
Income taxes payable
          138  
Fair value of commodity derivative instruments
    2,018        
Current portion of decommissioning liabilities
    23,588       20,097  
Current maturities of long-term debt
    11,810       14,210  
 
           
Total current liabilities
    130,708       104,211  
 
           
Deferred income taxes
    103,372       86,251  
Decommissioning liabilities
    90,430       18,756  
Long-term debt
    244,906       255,516  
Fair value of commodity derivative instruments
    618        
Stockholders’ equity:
               
Preferred stock of $0.01 par value. Authorized, 5,000,000 shares; none issued
           
Common stock of $0.001 par value. Authorized, 125,000,000 shares; issued and outstanding 76,766,303 and 74,099,081 shares at December 31, 2004 and 2003, respectively
    77       74  
Additional paid in capital
    398,073       370,798  
Accumulated other comprehensive income
    2,884       264  
Retained earnings (accumulated deficit)
    32,845       (3,007 )
 
           
Total stockholders’ equity
    433,879       368,129  
 
           
Total liabilities and stockholders’ equity
  $ 1,003,913     $ 832,863  
 
           

See accompanying notes to consolidated financial statements.

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Operations
Years Ended December 31, 2004, 2003 and 2002
(in thousands, except per share data)

                         
    2004     2003     2002  
Revenues
  $ 564,339     $ 500,625     $ 443,147  
 
                 
Costs and expenses:
                       
Cost of services
    310,108       289,607       258,334  
Depreciation, depletion, amortization and accretion
    67,337       48,853       41,595  
General and administrative
    110,605       94,822       86,197  
 
                 
Total costs and expenses
    488,050       433,282       386,126  
 
                 
Income from operations
    76,289       67,343       57,021  
Other income (expense):
                       
Interest expense, net of amounts capitalized
    (22,476 )     (22,477 )     (21,884 )
Interest income
    1,766       209       530  
Other income
          2,762        
Equity in earnings (loss) of affiliates
    1,329       985       (80 )
 
                 
Income before income taxes
    56,908       48,822       35,587  
Income taxes
    21,056       18,308       13,701  
 
                 
Net income
  $ 35,852     $ 30,514     $ 21,886  
 
                 
 
                       
Basic earnings per share
  $ 0.48     $ 0.41     $ 0.30  
 
                 
 
                       
Diluted earnings per share
  $ 0.47     $ 0.41     $ 0.30  
 
                 
 
                       
Weighted average common shares used in computing earnings per share:
                       
Basic
    74,896       73,970       72,912  
Incremental common shares from stock options
    1,004       678       960  
 
                 
Diluted
    75,900       74,648       73,872  
 
                 

See accompanying notes to consolidated financial statements.

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Changes in Stockholders’ Equity
Years Ended December 31, 2004, 2003 and 2002
(in thousands, except share data)

                                                                 
                                            Accumulated     Retained        
    Preferred             Common             Additional     other     earnings        
    stock     Preferred     stock     Common     paid-in     comprehensive     (Accumulated        
    shares     stock     shares     stock     capital     income (loss)     deficit)     Total  
     
Balances, December 31, 2001
        $       69,322,886     $ 69     $ 324,898     $ 16     $ (55,407 )   $ 269,576  
Comprehensive income:
                                                               
Net income
                                        21,886       21,886  
Other comprehensive income -
                                                               
Unrealized gain on derivatives
                                  18             18  
Foreign currency translation adjustment
                                  9             9  
     
Total comprehensive income
                                  27       21,886       21,913  
Stock issued for cash
                4,197,500       4       38,832                   38,836  
Exercise of stock options and related tax benefit, net, and directors’ stock compensation
                298,955       1       5,016                   5,017  
     
Balances, December 31, 2002
                73,819,341       74       368,746       43       (33,521 )     335,342  
Comprehensive income:
                                                               
Net income
                                        30,514       30,514  
Other comprehensive income -
                                                               
Foreign currency translation adjustment
                                  221             221  
     
Total comprehensive income
                                  221       30,514       30,735  
Exercise of stock options and related tax benefit, net, and directors’ stock compensation
                279,740             2,052                   2,052  
     
Balances, December 31, 2003
                74,099,081       74       370,798       264       (3,007 )     368,129  
Comprehensive income:
                                                               
Net income
                                        35,852       35,852  
Other comprehensive income -
                                                               
Changes in fair value of outstanding hedging positions, net of tax
                                  (1,661 )           (1,661 )
Foreign currency translation adjustment, net of tax
                                  4,281             4,281  
     
Total comprehensive income
                                  2,620       35,852       38,472  
Stock issued for cash
                11,151,121       12       130,253                   130,265  
Purchase and retirement of stock
                (9,696,627 )     (10 )     (113,428 )                 (113,438 )
Grant of restricted stock units
                            180                   180  
Conversion of restricted stock units
                9,783                                
Exercise of stock options and related tax benefit, net, and directors’ stock compensation
                1,202,945       1       10,270                   10,271  
     
Balances, December 31, 2004
        $       76,766,303     $ 77     $ 398,073     $ 2,884     $ 32,845     $ 433,879  
     

See accompanying notes to consolidated financial statements.

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Years Ended December 31, 2004, 2003 and 2002
(in thousands)

                         
    2004     2003     2002  
Cash flows from operating activities:
                       
Net income
  $ 35,852     $ 30,514     $ 21,886  
Adjustments to reconcile net income to net cash provided by operating activities:
                       
Depreciation, depletion, amortization and accretion
    67,337       48,853       41,595  
Deferred income taxes
    15,234       15,183       17,669  
Equity in (earnings) loss of affiliates
    (1,329 )     (985 )     80  
Other income
          (2,762 )      
Amortization of debt acquisition costs
    887       1,026       1,031  
Changes in operating assets and liabilities, net of acquisitions:
                       
Receivables
    (35,279 )     104       4,629  
Other — net
    (9,346 )     1,773       2,467  
Accounts payable
    16,142       (1,932 )     (1,660 )
Accrued expenses
    13,866       2,561       (7,466 )
Decommissioning liabilities
    (9,157 )            
Income taxes
    (2,876 )     5,905       7,052  
 
                 
Net cash provided by operating activities
    91,331       100,240       87,283  
 
                 
Cash flows from investing activities:
                       
Payments for purchases of property and equipment
    (74,125 )     (50,175 )     (104,452 )
Acquisitions of businesses, net of cash acquired
    (24,361 )     (14,298 )     (7,653 )
Acquisitions of oil and gas properties, net of cash acquired
    (10,676 )            
Cash proceeds from insurance settlement
          8,000        
Cash proceeds from asset disposition
          313        
Net cash used in investing activities
    (109,162 )     (56,160 )     (112,105 )
 
                 
Cash flows from financing activities:
                       
Net borrowings (payments) on revolving credit facility
          (9,250 )     1,550  
Principal payments on long-term debt
    (13,713 )     (43,089 )     (39,582 )
Proceeds from long-term debt
          23,000       20,241  
Payment of debt acquisition costs
    (60 )     (479 )     (1,529 )
Proceeds from exercise of stock options
    10,271       2,052       5,017  
Proceeds from issuance of stock
    130,265             38,836  
Purchase and retirement of stock
    (113,438 )            
 
                 
Net cash provided by (used in) financing activities
    13,325       (27,766 )     24,533  
 
                 
Effect of exchange rate changes in cash
    (7 )            
 
                 
Net increase (decrease) in cash and cash equivalents
    (4,513 )     16,314       (289 )
Cash and cash equivalents at beginning of year
    19,794       3,480       3,769  
 
                 
Cash and cash equivalents at end of year
  $ 15,281     $ 19,794     $ 3,480  
 
                 

See accompanying notes to consolidated financial statements.

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2004, 2003 and 2002

(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 2004 presentation.
 
  (b)   Business
 
      The Company is a leading provider of specialized oilfield services and equipment focusing on serving the production-related needs of oil and gas companies in the Gulf of Mexico and the drilling-related needs of oil and gas companies throughout the world. The Company provides most of the services, tools and liftboats necessary to maintain, enhance and extend offshore producing wells, as well as plug and abandonment services at the end of their life cycle.
 
      In December 2003, the Company began acquiring oil and gas properties in order to provide additional opportunities for its well intervention and platform management operations in the Gulf of Mexico. The Company intends to continue to acquire mature properties from its customers with modest amounts of estimated remaining productive life, to provide all of its services to the properties to produce any remaining proven oil and gas reserves and to decommission and abandon the properties.
 
  (c)   Use of Estimates
 
      The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
 
  (d)   Major Customers and Concentration of Credit Risk
 
      A majority of the Company’s business is conducted with major and independent oil and gas exploration companies. The Company continually evaluates the financial strength of its customers and provides allowances for probable credit losses when deemed necessary but does not require collateral to support the customer receivables.
 
      The market for the Company’s services and products is primarily the offshore oil and gas industry in the Gulf of Mexico. Oil and gas companies make capital expenditures on exploration, drilling and production operations offshore. The level of these expenditures has been characterized by significant volatility.
 
      The Company derives a significant amount of revenue from a small number of major and independent oil and gas companies. In 2004, 2003 and 2002, one customer accounted for approximately 7%, 11%, and 12% of its total revenue, respectively, primarily in the well intervention and other oilfield services segments. The Company’s inability to continue to perform services for a number of large existing customers, if not offset by sales to new or existing customers, could have a material adverse effect on the Company’s business and financial condition.

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  (e)   Cash Equivalents
 
      The Company considers all short-term deposits with a maturity of ninety days or less to be cash equivalents.
 
  (f)   Accounts Receivable and Allowances
 
      Trade accounts receivables are recorded at the invoiced amount and do not bear interest. The Company maintains allowances for bad debts and various other adjustments. The allowance for doubtful accounts is based on the Company’s best estimate of the amount of probable uncollectible amounts in existing accounts receivable. The Company determines the allowances based on historical write-off experience and specific identification.
 
  (g)   Property, Plant and Equipment
 
      Property, plant and equipment are stated at cost. Most of the Company’s 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, because depreciation and depletion occur primarily through use rather than through the passage of time. Units of production depreciation on marine vessels is subject to a minimum amount of depreciation each year.
 
      The Company capitalizes interest on borrowings used to finance the cost of major capital projects during the active construction period. Capitalized interest is added to the cost of the underlying assets and is amortized over the useful lives of the assets. For 2003 and 2002, the Company capitalized approximately $87,000 and $1,066,000, respectively, of interest for various capital expansion projects. There was no interest capitalized during 2004.
 
      Long-lived assets and certain identifiable intangibles are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the assets. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value. Assets 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 decommissioning liabilities. The Company follows the successful efforts method of accounting for its investment in oil and natural gas properties. Under the successful efforts method, the costs of successful exploratory wells and leases containing productive reserves are capitalized. Costs incurred to drill and equip developmental wells, including unsuccessful development wells are capitalized. Other costs such as geological and geophysical costs and the drilling costs of unsuccessful exploratory wells are expensed. SPN Resources’ property purchases are recorded at the value exchanged at closing, combined with an estimate of its proportionate share of the decommissioning liability assumed in the purchase. All capitalized costs are accumulated and recorded separately for each field and allocated to leasehold costs and well costs. Leasehold costs are depleted on a units-of-production basis based on the estimated remaining equivalent proved oil and gas reserves of each field. Well costs are depleted on a units-of-production basis based on the estimated remaining equivalent proved developed oil and gas reserves of each field.

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      Oil and gas properties are assessed for impairment in value on a field-by-field basis whenever indicators become evident. The Company uses its current estimate of future revenues and operating expenses to test the capitalized costs for impairment. In the event net undiscounted cash flows are less than the carrying value, an impairment loss is recorded based on the present value of expected future net cash flows over the economic lives of the reserves.
 
  (h)   Goodwill
 
      The Company accounts for goodwill and other intangible assets in accordance with Statement of Financial Accounting Standards No. 142 (FAS No. 142), “Goodwill and Other Intangible Assets.” FAS No. 142 requires that goodwill as well as other intangible assets with indefinite lives no longer be amortized, but instead tested annually for impairment. To test for impairment, the Company identifies its reporting units (which are consistent with the Company’s reportable segments) and determines the carrying value of each reporting unit by assigning the assets and liabilities, including goodwill and intangible assets, to the reporting units. The Company then estimates the fair value of each reporting unit and compares it to the reporting unit’s carrying value. Based on this test, the fair value of the reporting units exceeded the carrying amount, and the second step of the impairment test is not required. No impairment loss was recognized in the years ended December 31, 2004, 2003 or 2002. Accumulated amortization of goodwill is $9,151,000 at December 31, 2004 and 2003.
 
  (i)   Notes Receivable
 
      Notes receivable consist primarily of commitments from the sellers of oil and gas properties towards the abandonment of the acquired properties. Pursuant to the agreement between the Company and a seller, the Company will invoice the seller agreed upon amounts during the course of decommissioning (abandonment and structure removal). These receivables are recorded at present value, and the related discounts are amortized to interest income, based on the expected timing of the decommissionings.
 
  (j)   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 five to twenty-five years. The amortization of debt acquisition costs, which is classified as interest expense, was approximately $887,000, $1,026,000 and $1,031,000 for the years ended December 31, 2004, 2003 and 2002, respectively. Accumulated amortization of other assets is approximately $4,604,000 and $3,074,000 at December 31, 2004 and 2003, respectively.
 
  (k)   Decommissioning Liability
 
      The Company records estimated future decommissioning liabilities related to its oil and gas producing properties pursuant to the provisions of Statement of Financial Accounting Standards No. 143 (FAS No. 143), “Accounting for Asset Retirement Obligations.” FAS No. 143 requires entities to record the fair value of a liability at estimated present value for an asset retirement obligation (decommissioning liabilities) in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. Subsequent to initial measurement, the decommissioning liability is required to be accreted each period to present value. The Company’s decommissioning liabilities consist of costs related to the plugging of wells, the removal of facilities and equipment and site restoration on oil and gas properties.
 
      The Company estimates the cost that would be incurred if it contracted an unaffiliated third party to plug and abandon wells, abandon the pipelines, decommission and remove the platforms and pipelines and clear the sites of its oil and gas properties, and uses that estimate to record its proportionate share of the decommissioning liability. In estimating the decommissioning liability, the Company performs detailed estimating procedures, analysis and engineering studies. Whenever practical, the Company utilizes its own equipment and labor services to perform well abandonment and decommissioning work. When the Company performs these services, all recorded intercompany revenues are eliminated in the consolidated

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      financial statements. The recorded decommissioning liability associated with a specific property is fully extinguished when the property is abandoned. The recorded liability is first reduced by all cash expenses incurred to abandon and decommission the property. If the recorded liability exceeds (or is less than) the 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.
 
      SPN Resources purchased its first oil and gas properties and assumed the related decommissioning liabilities in December 2003, thus comparable data for the twelve months ended December 31, 2003 is not material. The following table summarizes the activity for the Company’s decommissioning liability for the twelve months ended December 31, 2004 (amounts in thousands):
         
    Year Ended  
    December 31,  
    2004  
Decommissioning liabilities, at beginning of period
  $ 38,853  
Liabilities acquired and incurred
    83,021  
Liabilities settled
    (9,157 )
Accretion
    2,836  
Revision in estimated liabilities
    (1,535 )
 
     
Total
    114,018  
Current portion of decommissioning liabilities
    23,588  
 
     
Decommissioning liabilities, at end of period
  $ 90,430  
 
     

  (l)   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.
 
  (m)   Income Taxes
 
      The Company provides for income taxes in accordance with Statement of Financial Accounting Standards No. 109 (FAS No. 109), “Accounting for Income Taxes.” FAS No. 109 requires an asset and liability approach for financial accounting and reporting for income taxes. Deferred income taxes reflect the impact of temporary differences between amounts of assets and liabilities for financial reporting purposes and such amounts as measured by tax laws.
 
  (n)   Earnings per Share
 
      Basic earnings per share is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share is computed in the same manner as basic earnings per share except that the denominator is increased to include the number of additional common shares that could have been outstanding assuming the exercise of stock options and restricted stock units and the potential shares that would have a dilutive effect on earnings per share.

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  (o)   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 $264.2 million at December 31, 2004.
 
  (p)   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.
 
  (q)   Stock Based Compensation
 
      The Company accounts for its stock based compensation under the principles prescribed by the Accounting Principles Board’s Opinion No. 25 (Opinion No. 25), “Accounting for Stock Issued to Employees” However, Statement of Financial Accounting Standards No. 123 (FAS No. 123), “Accounting for Stock-Based Compensation” permits the continued use of the intrinsic-value based method prescribed by Opinion No. 25 but requires additional disclosures, including pro forma calculations of earnings and net earnings per share as if the fair value method of accounting prescribed by FAS No. 123 had been applied. No stock based compensation costs from stock options are reflected in net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. Stock compensation costs from the grant of restricted stock units are expensed as incurred (see note 9). 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).

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    2004     2003     2002  
Net income, as reported
  $ 35,852     $ 30,514     $ 21,886  
Stock-based employee compensation expense, net of tax
    (6,999 )     (2,671 )     (3,262 )
 
                 
Pro forma net income
  $ 28,853     $ 27,843     $ 18,624  
 
                 
 
                       
Basic earnings per share:
                       
Earnings, as reported
  $ 0.48     $ 0.41     $ 0.30  
Stock-based employee compensation expense, net of tax
    (0.09 )     (0.04 )     (0.04 )
 
                 
Pro forma earnings per share
  $ 0.39     $ 0.37     $ 0.26  
 
                 
 
                       
Diluted earnings per share:
                       
Earnings, as reported
  $ 0.47     $ 0.41     $ 0.30  
Stock-based employee compensation expense, net of tax
    (0.09 )     (0.04 )     (0.05 )
 
                 
Pro forma earnings per share
  $ 0.38     $ 0.37     $ 0.25  
 
                 
 
                       
Black-Scholes option pricing model assumptions:
                       
Risk free interest rate
    4.28 %     2.65 %     2.94 %
Expected life (years)
    5       3       3  
Volatility
    65.22 %     58.61 %     85.48 %
Dividend yield
                 

  (r)   Hedging Activities
 
      The Company enters into hedging transactions with major financial institutions to secure a commodity price for a portion of future production and to reduce the Company’s exposure to fluctuations in the price of oil. The Company does not enter into hedging transactions for trading purposes. Crude oil hedges are settled based on the average of the reported settlement prices for West Texas Intermediate crude on the New York Mercantile Exchange (NYMEX) for each month. The Company had no natural gas hedges as of December 31, 2004. The Company uses financially-settled crude oil swaps and zero-cost collars that provide floor and ceiling prices with varying upside price participation. The Company’s swaps and zero-cost collars are designated and accounted for as cash flow hedges.
 
      With a financially-settled swap, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the hedged price for the transaction, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. With a zero-cost collar, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price of the collar, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar. The Company recognizes the fair value of all derivative instruments as assets or liabilities on the balance sheet. Changes in the fair value of cash flow hedges are recognized, to the extent the hedge is effective, in other comprehensive income until the hedged item is settled and recorded in revenue. For the year ended December 31, 2004, hedging settlement payments reduced oil revenues by $1.6 million dollars. The Company recognized no gains or losses due to hedge ineffectiveness, but any gains or losses resulting from hedge ineffectiveness would be recorded in revenue.

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      The Company had the following hedging contracts as of December 31, 2004:
                         
Crude Oil Positions
    Instrument   Strike   Volume (Bbls)    
Remaining Contract Term   Type   Price (Bbl)   Daily   Total (Bbls)
01/05 — 8/06
  Swap   $ 39.45     1,000 — 1,225     683,801  
01/05 — 8/06
  Collar   $ 35.00/$45.60     1,000 — 1,225     683,801  

      Based upon current market prices, the Company expects to transfer approximately $1.3 million of net deferred losses in accumulated other comprehensive loss as of December 31, 2004 to earnings during the next twelve months when the forecasted transactions actually occur.
 
  (s)   Other Comprehensive Income
 
      The following table reconciles the change in accumulated other comprehensive income for the years ended December 31, 2004 and 2003 (amounts in thousands):
                 
    Year Ended December 31,  
    2004     2003  
Accumulated other comprehensive income, December 31, 2003 and 2002, respectively
  $ 264     $ 43  
 
               
Other comprehensive income (loss), net of tax:
               
Hedging activities:
               
Reclassification adjustment for settled contracts, net of tax of $576 in 2004
    981        
Changes in fair value of outstanding hedging positions, net of tax of ($1,552) in 2004
    (2,642 )      
Foreign currency translation adjustment, net of tax of $2,669 in 2004, $0 in 2003
    4,281       221  
 
           
Total other comprehensive income
    2,620       221  
 
           
 
               
Accumulated other comprehensive income, December 31, 2004 and 2003, respectively
  $ 2,884     $ 264  
 
           

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(2)   Supplemental Cash Flow Information

The following table includes the Company’s supplemental cash flow information for the years ended December 31, 2004, 2003 and 2002 (amounts in thousands):

                         
    2004     2003     2002  
Cash paid for interest
  $ 23,320     $ 23,633     $ 22,006  
 
                 
 
                       
Cash paid (received) for income taxes
  $ 7,360     $ (4,125 )   $ (15,224 )
 
                 
 
                       
Details of business acquisitions:
                       
Fair value of assets
  $ 25,614     $ 51,103     $ 29,985  
Fair value of liabilities
    (1,158 )     (35,270 )     (22,093 )
 
                 
Cash paid
    24,456       15,833       7,892  
Less cash acquired
    (95 )     (1,535 )     (239 )
 
                 
Net cash paid for acquisitions
  $ 24,361     $ 14,298     $ 7,653  
 
                 
 
                       
Details of oil and gas property acquisitions:
                       
Fair value of assets
  $ 97,792     $ 39,509     $  
Fair value of liabilities
    (82,107 )     (39,509 )      
 
                 
Cash paid
    15,685              
Less cash acquired
    (5,009 )            
 
                 
Net cash paid for acquisitions
  $ 10,676     $     $  
 
                 
 
                       
Non-cash investing activity:
                       
Additional consideration payable on acquisitions
  $ 5,272     $ 11,263     $ 660  
 
                 
 
                       
Note receivable from asset disposition
  $     $ 938     $  
 
                 

(3)   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. 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.

(4)   Acquisitions and Dispositions

In December 2004, the Company’s wholly-owned subsidiary, SPN Resources, LLC, acquired additional oil and gas properties at West Delta 79/86 through the acquisition of 100% working interests in seven leases on five shallow water Gulf of Mexico blocks, which included eight platforms and more than 100 wells. Under the terms of the transaction, the Company acquired the properties and assumed the decommissioning liabilities. Concurrently with this transaction, the Company also sold a portion of the behind pipe reserves and exploration rights. The Company retained an overriding royalty interest in any new drill well opportunities identified with the option to participate instead on a well-by-well basis for a working interest. The Company received $3.7 million net cash at closing from the two transactions. The Company preliminarily recorded a decommissioning liability of $29.4 million, and oil and gas producing assets were recorded at their estimated fair value of $25.7 million.

In July 2004, SPN Resources, LLC, acquired additional oil and gas properties at South Pass 60 through the acquisition of nine offshore Gulf of Mexico leases. The purchase included 100% working interest in these nine leases on seven shallow water Gulf of Mexico blocks, nine structures, several pipelines and approximately 125

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productive wells. Under the terms of the transaction, the Company paid approximately $15.6 million in cash, acquired the properties and assumed the related decommissioning liabilities. The Company preliminarily recorded receivables of approximately $2.1 million decommissioning liabilities of $39.2 million and oil and gas producing assets were recorded at their estimated fair value of $52.7 million.

In the first quarter of 2004, SPN Resources, LLC, acquired additional oil and gas properties through the acquisition of interests in three offshore Gulf of Mexico leases. Under the terms of the transactions, the Company acquired the properties and assumed the decommissioning liabilities. The Company received $1.2 million cash and will invoice the sellers at agreed upon prices as the decommissioning activities (abandonment and structure removal) are completed. The Company preliminarily recorded notes receivable of $10.4 million and a decommissioning liability of $14.4 million. Oil and gas producing assets were recorded at their estimated fair value of $2.8 million. The pro forma effect of operations of these acquisitions when included as of the beginning of the periods presented was not material to the Company’s Consolidated Statements of Operations and are not included in the table below.

In 2004, the Company acquired two businesses for an aggregate of $2.8 million in cash consideration in order to enhance the products and services offered by its rental tools segment and well intervention segment. Additional consideration, if any, will be based upon the average EBITDA less certain adjustments over a three-year period, and will not exceed $2.8 million in the aggregate for both acquisitions. These acquisitions have been accounted for as purchases and the acquired assets and liabilities have been valued at their estimated fair value. The purchase price preliminarily allocated to net assets was approximately $1.0 million in the aggregate, and the excess purchase price over the fair value of net assets of approximately $1.8 million in the aggregate was allocated to goodwill. The results of operations have been included from the acquisition dates.

In December 2003, SPN Resources acquired oil and gas properties through the acquisition of interests in 24 offshore Gulf of Mexico leases. 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 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.

In August 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 and $25.8 million of the Company’s revenues in the years ended December 31, 2003 and 2002, respectively.

In August 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 Premier’s 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 following unaudited pro forma information for the years ended December 31, 2004 and 2003 presents a summary of the consolidated results of operations as if the acquisitions and disposition described above as well as the equity offering described in note 9 had occurred on January 1, 2003, with pro forma adjustments to give effect to depreciation, depletion, interest and certain other adjustments, together with related income tax effects (in thousands, except per share amounts):

                 
    Years Ended December 31,  
    2004     2003  
Revenues
  $ 610,064     $ 612,229  
 
           
Net income
  $ 41,350     $ 39,388  
 
           
Basic earnings per share
  $ 0.54     $ 0.52  
 
           
Diluted earnings per share
  $ 0.54     $ 0.52  
 
           

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The above pro forma information is not necessarily indicative of the results of operations that would have been achieved had the acquisition been effected January 1, 2003.

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 $2.8 million. 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. 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, 2004, the Company capitalized additional consideration of $16.2 million related to two of its acquisitions, of which $10.9 million was paid during 2004 and $5.3 million was paid in the first quarter of 2005.

(5)   Property, Plant and Equipment

A summary of property, plant and equipment at December 31, 2004 and 2003 (in thousands) is as follows:

                 
    2004     2003  
Buildings and improvements
  $ 57,624     $ 49,964  
Marine vessels and equipment
    193,321       188,056  
Machinery and equipment
    342,700       297,601  
Oil and gas assets
    91,104       5,468  
Automobiles, trucks, tractors and trailers
    10,248       10,482  
Furniture and fixtures
    11,944       9,948  
Construction-in-progress
    2,498       2,594  
Land
    6,037       6,148  
 
           
 
    715,476       570,261  
Accumulated depreciation
    (200,325 )     (142,901 )
 
           
 
               
Property, plant and equipment, net
  $ 515,151     $ 427,360  
 
           

Amounts of property, plant and equipment leased to third parties at December 31, 2004 and 2003 were not material. Depreciation expense (excluding depletion, amortization and accretion) was approximately $57.1 million, $48.5 million, and $41.2 million for the years ended December 31, 2004, 2003 and 2002, respectively.

(6)   Investments in Affiliates

The Company has a 54.3% equity ownership interest in Lamb Energy Services, LLC, 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. At December 31, 2004, the Company’s balance of investments in affiliates was $14.5 million. Included in this balance is approximately $6.4 million of goodwill related to the investment in Lamb Energy. The equity in income from these investments was approximately $1,329,000 and $985,000 for the years ended December 31, 2004 and 2003, respectively, 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 Company’s financial position or results of operations.

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(7) Debt

Long-Term Debt

The Company’s long-term debt as of December 31, 2004 and 2003 consisted of the following (in thousands):

                 
    2004     2003  
Senior Notes — interest payable semiannually at 8.875%, due May 2011
  $ 200,000     $ 200,000  
Term Loans — interest payable monthly at floating rate (4.89% at December 31, 2004), due in quarterly installments of $2.75 million through June 2008
    38,500       50,700  
Revolver — interest payable monthly at floating rate, due in August 2006
           
U.S. Government guaranteed long-term financing — interest payable semianually at 6.45%, due in semiannual installments through June 2027
    18,216       19,026  
 
           
 
    256,716       269,726  
Less current portion
    11,810       14,210  
 
           
Long-term debt
  $ 244,906     $ 255,516  
 
           

The Company has a bank credit facility consisting of term loans in an aggregate amount of $38.5 million outstanding at December 31, 2004, and a revolving credit facility of $75 million, none of which was outstanding at December 31, 2004. The credit facility was amended effective June 30, 2004, to extend the maturity date of one of the term loans. As amended, the term loans require principal payments of $2.8 million each quarter through June 30, 2008. 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, incur additional indebtedness, or assume additional decommissioning liabilities. Subsequent to year-end, the Company amended its bank credit facility to permit it to incur additional secured indebtedness of up to $5.0 million. The Company also has letters of credit outstanding of approximately $7.0 million at December 31, 2004, which reduce the borrowing availability under our revolving credit facility. The letters of credit are primarily extended to certain insurance companies to secure our payments.

The Company has $18.2 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. This long-term financing ranks equally with the bank credit facility as both are secured by unique assets.

The Company also has outstanding $200 million of 8 7/8% unsecured senior notes due 2011. The indenture governing the notes requires semi-annual interest payments, on every November 15th and May 15th through the maturity date of May 15, 2011. The 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 $180 million at December 31, 2004. The indenture also contains covenants that restrict the Company’s ability to create certain liens, sell assets, or enter into certain mergers or acquisitions.

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Annual maturities of long-term debt for each of the five fiscal years following December 31, 2004 are as follows (in thousands):

         
2005
  $ 11,810  
2006
    11,810  
2007
    11,810  
2008
    6,310  
2009
    810  
Thereafter
    214,166  
 
     
Total
  $ 256,716  
 
     

(8) Income Taxes

The components of income tax expense (benefit) for the years ended December 31, 2004, 2003 and 2002 are as follows (in thousands):

                         
    2004     2003     2002  
Current
                       
Federal
  $ 87     $ 515     $ (5,042 )
State
    415       245       199  
Foreign
    5,320       2,365       875  
 
                 
 
    5,822       3,125       (3,968 )
 
                 
Deferred
                       
Federal
    17,569       14,561       16,801  
State
    105       1,220       868  
Foreign
    (2,440 )     (598 )      
 
                 
 
    15,234       15,183       17,669  
 
                 
 
  $ 21,056     $ 18,308     $ 13,701  
 
                 

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):

                         
    2004     2003     2002  
Computed expected tax expense
  $ 19,918     $ 17,088     $ 12,456  
Increase resulting from:
                       
State and foreign income taxes
    178       478       1,068  
Other
    960       742       177  
 
                 
Income tax expense
  $ 21,056     $ 18,308     $ 13,701  
 
                 

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The significant components of deferred income taxes at December 31, 2004 and 2003 are as follows (in thousands):

                 
    2004     2003  
Deferred tax assets:
               
Allowance for doubtful accounts
  $ 776     $ 951  
Alternative minimum tax credit and net operating loss carryforward
    12,358       15,481  
Decommissioning liability
    42,187        
Other
    5,133       2,184  
 
           
Net deferred tax assets
    60,454       18,616  
 
           
Deferred tax liabilities:
               
Property, plant and equipment
    133,710       93,218  
Note receivable
    14,103        
Other
    16,013       11,649  
 
           
Deferred tax liabilities
    163,826       104,867  
 
           
Net deferred tax liability
  $ 103,372     $ 86,251  
 
           

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. A valuation allowance is recognized if it is more likely than not that at least some portion of any deferred tax asset will not be realized.

As of December 31, 2004, the Company has not established a valuation reserve for its deferred tax assets. The Company believes that it is more likely than not that the tax assets will be realized because of the reversal of accelerated tax depreciation and future taxable income.

As of December 31, 2004, the Company has an estimated $5.5 million net operating loss carryforward, which is available to reduce future Federal taxable income with expiration dates from 2008 through 2023, an estimated $1.7 million alternative minimum tax credit carryforward, and an estimated $5.3 million foreign tax credit carryforward with expiration dates from 2011 through 2014. As of December 31, 2004, the Company also has various state net operating loss carryforwards of an estimated $65 million with expiration dates from 2013 through 2017.

As of December 31, 2004, the Company has not provided United States tax expense on earnings of its foreign subsidiaries, since the Company has reinvested or expects to reinvest the undistributed earnings indefinitely. As of December 31, 2004, the undistributed earnings of the Company’s foreign subsidiaries were approximately $11.7 million. If these earnings are repatriated to the United States in the future, additional tax provisions may be required.

The American Jobs Creation Act of 2004 was passed on October 22, 2004. This legislation allows, under certain conditions, a one-time tax deduction of 85% of certain foreign earnings that are repatriated prior to the end of the Company’s fiscal 2005 year. The deduction would result in a 5.25% federal tax rate on the repatriated earnings. The Company is in the process of evaluating whether any of its foreign earnings will qualify for the temporary deduction and whether it will repatriate all or a portion of any qualifying foreign earnings.

As of December 31, 2004, the Company has not determined whether earnings will be repatriated or an estimate of the possible United States federal and state income tax expense related to any potential repatriation. The Company expects to make its decision prior to December 31, 2005.

(9) Stockholders’ Equity

In October 2004, the Company sold 9,696,627 shares of common stock that generated net proceeds (before any exercise of the underwriters’ over-allotment option) of approximately $113 million, after deducting underwriting discounts and commissions and the estimated offering expenses. The Company used the net proceeds to repurchase 9,696,627 shares of its common stock from First Reserve Fund VII, Limited Partnership and First Reserve Fund

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VIII, L.P. The shares repurchased by the Company from the First Reserve funds were retired immediately upon repurchase. In November 2004, an additional 1,454,494 shares of the Company’s common stock were issued pursuant to the exercise of the underwriters’ over-allotment option generating net proceeds of approximately $17 million, after deducting underwriting discounts and commissions.

In 2004, the Superior Energy Services, Inc. 2004 Directors Restricted Stock Units Plan was approved by the Company’s stockholders. This plan provides each non-employee director is granted a number of restricted stock units having an aggregate value of $30,000, with the exact number of units determined by dividing $30,000 by the fair market value of the Company’s common stock on the day of the annual stockholders’ meeting. In addition, upon any person’s initial election or appointment as an eligible director, other than at an annual stockholders’ meeting, such person will receive a pro forma number of restricted stock units based on the number of full calendar months between the date of grant and the first anniversary of the previous annual stockholders’ meeting. A restricted stock unit represents the right to receive from the Company, within 30 days of the date the participant ceases to serve on the Board, one share of the Company’s common stock. As a result of this plan, 9,783 restricted stock units are outstanding at December 31, 2004.

In March 2002, the Company sold 4.2 million shares of common stock. The offering generated net proceeds to the Company of approximately $39 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 (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 Company’s Board of Directors establishes the term and the exercise price of any stock options granted under the 2002 Incentive Plan, provided the exercise price may not be less than the fair value of the common share on the date of grant. All of the options which have been granted under the 1995 Stock Incentive Plan are vested.

A summary of stock options granted under the incentive plans for the years ended December 31, 2004, 2003 and 2002 is as follows:

                                                 
    2004     2003     2002  
            Weighted             Weighted             Weighted  
    Number of     Average     Number of     Average     Number of     Average  
    Shares     Price     Shares     Price     Shares     Price  
Outstanding at beginning of year
    5,628,000     $ 7.53       5,518,516     $ 7.33       5,308,215     $ 7.05  
Granted
    1,490,000     $ 10.66       538,000     $ 8.94       655,841     $ 9.39  
Exercised
    (1,196,060 )   $ 7.01       (271,913 )   $ 6.72       (290,665 )   $ 5.96  
Forfeited
    (124,645 )   $ 8.14       (156,603 )   $ 7.00       (154,875 )   $ 8.89  
 
                                         
Outstanding at end of year
    5,797,295     $ 8.43       5,628,000     $ 7.53       5,518,516     $ 7.33  
 
                                   
Exercisable at end of year
    5,328,741     $ 8.37       4,248,244     $ 7.08       3,509,008     $ 6.61  
 
                                   
Available for future grants
    35,746               1,401,101               1,782,498          
 
                                         
Average fair value of grants during the year
          $ 6.22             $ 3.59             $ 5.33  
 
                                         

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A summary of information regarding stock options outstanding at December 31, 2004 is as follows:

                                         
    Options Outstanding     Options Exercisable  
Range of           Weighted Average     Weighted             Weighted  
Exercise           Remaining     Average             Average  
Prices   Shares     Contractual Life     Price     Shares     Price  
 
$2.50 - $3.43
    46,000     1.0 years   $ 2.57       46,000     $ 2.57  
$4.75 - $5.75
    1,464,117     4.4 years   $ 5.72       1,464,117     $ 5.72  
$7.06 - $9.00
    1,513,883     6.4 years   $ 8.11       1,242,165     $ 7.97  
$9.10-$12.45
    2,773,295     8.1 years   $ 10.12       2,576,459     $ 10.17  

(10) Profit-Sharing Plan

The Company maintains a defined contribution profit-sharing plan for employees who have satisfied minimum service and age requirements. Employees may contribute up to 75% of their earnings to the plans. The Company provides a discretionary match, not to exceed 5% of an employee’s salary. The Company made contributions of approximately $1.7 million, $1.6 million and $1.7 million, in 2004, 2003 and 2002, respectively.

The Company began a nonqualified defined contribution deferred compensation plan in the fourth quarter of 2004. The plan allows certain eligible employees to defer up to 75% of their salary and up to 100% of their bonus compensation to the plan. The Company maintains the assets and has a liability recorded equal to the earnings deferrals and investment income. At December 31, 2004, the asset and liability related to this plan were not material.

(11) Commitments and Contingencies

The Company leases certain office, service and assembly facilities under operating leases. The leases expire at various dates over the next several years. Total rent expense was approximately $4.2 million in 2004, $2.3 million in 2003 and $3.0 million in 2002. Future minimum lease payments under non-cancelable leases for the five years ending December 31, 2005 through 2009 and thereafter are as follows: $5,047,000, $3,887,000, $2,639,000, $1,415,000, $517,000 and $13,735,000, respectively. Future minimum lease payments receivable under non-cancelable sub-leases for the five years ending December 31, 2005 through 2008 are as follows: $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 its financial position, results of operations or liquidity.

(12) Segment Information

Business Segments

The Company has modified its segment disclosure by breaking out its oil and gas operations from the well intervention segment. This change better reflects the impact of the oil and gas operations and service work created for the other segments, as well as how the Company’s management evaluates its results of operations. The Company’s reportable segments are now as follows: well intervention, marine, rental tools, other oilfield services and oil and gas. The first four segments offer products and services within the oilfield services industry. The well intervention segment provides plug and abandonment services, coiled tubing services, well pumping and stimulation services, data acquisition services, gas lift services, electric wireline services, hydraulic drilling and workover services, well control services 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 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

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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. The oil and gas segment acquires mature oil and gas reserves and produces these reserves for as long as economically viable. Then, the Company’s other segments provide decommissioning services. The Company’s first acquisition of oil and gas properties was in December 2003.

The accounting policies of the reportable segments are the same as those described in Note 1 of these Notes to the Consolidated Financial Statements. The Company evaluates the performance of its operating segments based on operating profits or losses. Segment revenues reflect direct sales of products and services for that segment, and each segment records direct expenses related to its employees and its operations. Identifiable assets are primarily those assets directly used in the operations of each segment.

Summarized financial information concerning the Company’s segments as of December 31, 2004, 2003 and 2002 and for the years then ended is shown in the following tables (in thousands):

                                                         
                            Other             Oil & Gas        
    Well     Rental             Oilfield             Eliminations     Consolid.  
2004   Interven.     Tools     Marine     Services     Oil & Gas     & Unallocated     Total  
     
Revenues
  $ 211,820     $ 170,064     $ 69,808     $ 83,870     $ 37,008     $ (8,231 )   $ 564,339  
Costs of services
    122,065       57,353       49,581       67,793       21,547       (8,231 )     310,108  
Depreciation, depletion, amortization and accretion
    13,546       32,527       7,362       3,889       10,013             67,337  
General and administrative
    43,912       42,165       7,085       14,791       2,652             110,605  
Operating income (loss)
    32,297       38,019       5,780       (2,603 )     2,796             76,289  
Interest expense
                                  (22,476 )     (22,476 )
Interest income
                            1,648       118       1,766  
Equity in earnings of affiliates
          1,329                               1,329  
     
Income (loss) before income taxes
  $ 32,297     $ 39,348     $ 5,780     $ (2,603 )   $ 4,444     $ (22,358 )   $ 56,908  
     
Identifiable assets
  $ 258,870     $ 357,762     $ 184,928     $ 54,561     $ 141,179     $ 6,613     $ 1,003,913  
Capital expenditures
  $ 11,124     $ 50,687     $ 5,523     $ 1,611     $ 5,180     $     $ 74,125  

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                            Other                        
    Well     Rental             Oilfield                     Consolid.  
2003   Interven.     Tools     Marine     Services     Oil & Gas     Unallocated     Total  
     
Revenues
  $ 187,271     $ 141,362     $ 70,370     $ 100,881     $ 741     $     $ 500,625  
Costs of services
    111,330       46,119       50,314       81,513       331             289,607  
Depreciation, depletion, amortization and accretion
    12,231       25,696       6,665       4,130       131             48,853  
General and administrative
    39,572       33,457       7,122       14,643       28             94,822  
Operating income
    24,138       36,090       6,269       595       251             67,343  
Interest expense
                                  (22,477 )     (22,477 )
Interest income
                            51       158       209  
Other income
                2,762                         2,762  
Equity in earnings of affiliates
          985                               985  
     
Income (loss) before income taxes
  $ 24,138     $ 37,075     $ 9,031     $ 595     $ 302     $ (22,319 )   $ 48,822  
     
Identifiable assets
  $ 224,022     $ 314,122     $ 181,752     $ 64,421     $ 41,315     $ 7,231     $ 832,863  
 
                                                       
Capital expenditures
  $ 15,248     $ 30,192     $ 2,043     $ 2,692     $     $     $ 50,175  
                                                 
                            Other                
    Well     Rental             Oilfield             Consolidated  
2002   Intervention     Tools     Marine     Services     Unallocated     Total  
     
Revenues
  $ 148,670     $ 124,085     $ 67,884     $ 102,508     $     $ 443,147  
Costs of services
    93,474       38,375       44,648       81,837             258,334  
Depreciation, depletion, amortization and accretion
    10,625       19,822       6,764       4,384             41,595  
General and administrative
    34,520       29,846       7,463       14,368             86,197  
Operating income
    10,051       36,042       9,009       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     $ 35,962     $ 9,009     $ 1,919     $ (21,354 )   $ 35,587  
     
Identifiable assets
  $ 199,084     $ 261,341     $ 195,832     $ 63,491     $ 7,872     $ 727,620  
 
                                               
Capital expenditures
  $ 18,058     $ 41,931     $ 38,833     $ 5,630     $     $ 104,452  

Geographic Segments

The Company attributes revenue to various countries based on the location of where services are performed or the destination of the sale of products. Long-lived assets consist primarily of property, plant, and equipment and are attributed to various countries based on the physical location of the asset at a given fiscal year-end. The Company’s information by geographic area is as follows (amounts in thousands):

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    Revenues     Long-Lived Assets  
    Years Ended December 31,     December 31,  
    2004     2003     2002     2004     2003  
United States
  $ 476,771     $ 443,936     $ 404,295     $ 479,812     $ 400,600  
Other Countries
    87,568       56,689       38,852       35,339       26,760  
         
Total
  $ 564,339     $ 500,625     $ 443,147     $ 515,151     $ 427,360  
         

(13) Interim Financial Information (Unaudited)

The following is a summary of consolidated interim financial information for the years ended December 31, 2004 and 2003 (amounts in thousands, except per share data):

                                 
    Three Months Ended  
    March 31     June 30     Sept. 30     Dec. 31  
2004
                               
Revenues
  $ 116,459     $ 137,545     $ 152,500     $ 157,835  
Gross profit
    49,754       60,401       70,089       73,987  
Net income
    3,564       8,714       11,288       12,286  
 
                               
Earnings per share:
                               
Basic
  $ 0.05     $ 0.12     $ 0.15     $ 0.16  
Diluted
    0.05       0.12       0.15       0.16  
                                 
    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  

(14) Supplementary Oil and Natural Gas Disclosures – (Unaudited)

The Company’s December 31, 2004 estimates of proved reserves are based on reserve reports prepared by DeGolyer and MacNaughton, independent petroleum engineers. The estimates of proved reserves at December 31, 2003 are based on internal reports. Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. This data may also change substantially over time as a result of multiple factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures. Proved reserves are estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

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The following table sets forth the Company’s net proved reserves, including the changes therein, and proved developed reserves:

                 
    Crude Oil     Natural Gas  
    (Mbbls)     (Mmcf)  
Proved-developed and undeveloped reserves:
               
December 31, 2002
           
Purchase of reserves in place
    193       3,304  
Revisions
          (1 )
Production
    (3 )     (79 )
 
           
December 31, 2003
    190       3,224  
Purchase of reserves in place
    9,232       17,968  
Revisions
    88       11,407  
Production
    (390 )     (3,219 )
 
           
December 31, 2004
    9,120       29,380  
 
           
 
               
Proved-developed reserves:
               
December 31, 2002
           
December 31, 2003
    64       3,190  
December 31, 2004
    7,731       25,542  

The Company filed no reserve estimates with any Federal authorities or agencies during 2004.

Costs incurred for oil and natural gas property acquisition and development activities for the years ended December 31, 2004 and 2003 are as follows (in thousands):

                 
    Years Ended December 31,  
    2004     2003  
Acquisition of properties — proved
  $ 81,356     $ 5,041  
Development costs
    4,707        
 
           
Costs incurred
    86,063       5,041  
 
           
Asset retirement liabilities incurred
    83,021       38,853  
Asset retirement revisions
    (1,535 )      
 
           
Total costs incurred
  $ 167,549     $ 43,894  
 
           

The asset retirement liability amounts incurred do not give any effect to the Company’s contractual right to receive amounts from third parties, which is approximately $38.7 million, when decommissioning operations are completed.

Standardized Measure of Discounted Future Net Cash Flows Relating to Reserves

The following information has been developed utilizing procedures prescribed by Statement of Financial Accounting Standards No. 69 (FAS No. 69), “Disclosure about Oil and Gas Producing Activities.” It may be useful for certain comparative purposes, but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company.

The Company believes that the following factors should be taken into account in reviewing the following information: (1) future costs and selling prices will probably differ from those required to be used in these calculations; (2) due to future market conditions and governmental regulations, actual rates of production achieved in future years may vary significantly from the rate of production assumed in the calculations; (3) selection of a 10%

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discount rate is arbitrary and may not be reasonable as a measure of the relative risk inherent in realizing future net oil and gas revenues; and (4) future net revenues may be subject to different rates of income taxation.

Under the Standardized Measure, future cash inflows were estimated by applying period end oil and natural gas prices adjusted for differentials provided by the Company. Future cash inflows were reduced by estimated future development, abandonment and production costs based on period-end costs in order to arrive at net cash flow before tax. Future income tax expense has been computed by applying period-end statutory tax rates to aggregate future net cash flows, reduced by the tax basis of the properties involved and tax carryforwards. Use of a 10% discount rate is required by FAS No. 69.

The Company’s management does not rely solely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows (in thousands):

                 
    2004     2003  
Future cash inflows
  $ 587,277     $ 26,002  
Future production costs
    (148,610 )     (12,603 )
Future development and abandonment costs
    (153,230 )     (6,641 )
Future income tax expense
    (119,567 )     (2,748 )
 
           
Future net cash flows after income taxes
    165,870       4,010  
10% annual discount for estimated timing of cash flows
    29,363       20  
 
           
Standardized measure of discounted future net cash flows
  $ 136,507     $ 3,990  
 
           

A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves for the years ended December 31, 2004 and 2003 is as follows (in thousands):

                 
    2004     2003  
Beginning of the period
  $ 3,990     $  
Sales and transfers of oil and natural gas produced, net of production costs
    (15,467 )     (470 )
Net changes in prices and production costs
    949       (1 )
Revisions of quantity estimates
    46,040       (8 )
Development costs incurred
    4,707        
Changes in estimated development costs
    (99,253 )     (5,496 )
Purchase and sales of reserves in place
    282,935       12,552  
Changes in production rates (timing) and other
    (3,238 )     (13 )
Accretion of discount
    656        
Net change in income taxes
    (84,812 )     (2,574 )
 
           
Net increase
    132,517       3,990  
 
           
End of period
  $ 136,507     $ 3,990  
 
           

The December 31, 2004 amount was estimated by DeGolyer and MacNaughton using a period-end crude NYMEX price of $43.46 per barrel (Bbl), a Henry Hub gas price of $6.19 per million British Thermal units, and price differentials provided by the Company. The December 31, 2003 amount was estimated by the Company using a period end oil price of $32.55 per Bbl and $6.14 per thousand cubic feet (Mcf) for natural gas. The Company had no oil and gas holdings prior to 2003. Spot prices as of February 28, 2005 were $6.73 per million British Thermal units for natural gas and $51.75 per Bbl for crude oil.

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(15)   Accounting Pronouncements

In November 2004, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 151 (FAS No. 151), “Inventory Costs.” The Statement amends Accounting Research Bulletin No. 43 (ARB No. 43), “Inventory Pricing,” to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material. ARB No. 43 previously stated that these costs must be “so abnormal as to require treatment as current-period charges.” FAS No. 151 requires that those items be recognized as current-period charges regardless of whether they meet the criterion of “so abnormal.” In addition this Statement requires that allocation of fixed production overhead to the costs of conversion be based on the normal capacity of the production facilities. This Statement is effective for inventory costs incurred during fiscal years beginning after June 15, 2005, with earlier application permitted for fiscal years beginning after the issue date of the Statement. The Company does not believe the adoption of FAS No. 151 will have a significant impact on its financial condition and results of operations.

In December 2004, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 152 (FAS No. 152), “Accounting for Real Estate Time-Sharing Transactions – An Amendment of FASB Statements No. 66 and 67,” which states that the guidance for incidental operations and costs incurred to sell real estate projects does not apply to real estate time-sharing transactions. The Company does not believe the adoption of FAS No. 152 will have a significant impact on its financial condition and results of operations.

In December 2004, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 153 (FAS No. 153), “Exchanges of Nonmonetary Assets – An Amendment of APB Opinion No. 29.” APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” is based on the opinion that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. FAS No. 153 amends Opinion No. 29 to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets whose results are not expected to significantly change the future cash flows of the entity. The Company does not believe the adoption of FAS No. 153 will have a significant impact on our financial condition and results of operations.

In December 2004, the Financial Accounting Standards Board revised its Statement of Financial Accounting Standards No. 123 (FAS No. 123R), “Accounting for Stock Based Compensation.” The revision establishes standards for the accounting of transactions in which an entity exchanges its equity instruments for goods or services, particularly transactions in which an entity obtains employee services in share-based payment transactions. The revised statement requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. That cost is to be recognized over the period during which the employee is required to provide service in exchange for the award. Changes in fair value during the requisite service period are to be recognized as compensation cost over that period. In addition, the revised statement amends Statement of Financial Accounting Standards No. 95, “Statement of Cash Flows,” to require that excess tax benefits be reported as a financing cash flow rather than as a reduction of taxes paid. The provisions of the revised statement are effective for financial statements issued for the first interim or annual reporting period beginning after June 15, 2005, with early adoption encouraged. If the Company had adopted this Statement during 2004, it would have recognized $7 million of additional expense, net of tax.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

Our management has established and maintains a system of disclosure controls and procedures to provide reasonable assurances that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as

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appropriate, to allow timely decisions regarding required disclosure based closely on the definition of “disclosure controls and procedures” in Rule 13a-15(e) of the Securities Exchange Act of 1934. We also have investments in certain unconsolidated entities. As we do not control or manage these entities, our disclosure controls and procedures with respect to such entities are necessarily substantially more limited than those we maintain with respect to our consolidated subsidiaries.

Management’s Annual Report on Internal Control Over Financial Reporting

As of December 31, 2004, our management, including our principal executive officer and principal financial officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(e) of the Securities Exchange Act of 1934. Based on this evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures as of December 31, 2004 are effective in providing reasonable assurance that the information required to be disclosed by us in reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Management’s report and the independent registered public accounting firm’s attestation report are included in Item 8 under the captions “Management’s Report on Internal Control over Financial Reporting” and “Independent Registered Public Accounting Firm’s Report,” and are incorporated herein by reference.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the quarter ended December 31, 2004 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None.

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PART III

Item 10. Directors and Executive Officers of the Registrant

Information required by this item will be contained in our definitive proxy statement to be filed pursuant to Regulation 14A and is incorporated herein by reference.

Item 11. Executive Compensation

Information required by this item will be contained in our definitive proxy statement to be filed pursuant to Regulation 14A and is incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information required by this item will be contained in our definitive proxy statement to be filed pursuant to Regulation 14A and is incorporated herein by reference.

Item 13. Certain Relationships and Related Transactions

Information required by this item will be contained in our definitive proxy statement to be filed pursuant to Regulation 14A and is incorporated herein by reference.

Item 14. Principal Accountant Fees and Services

Information required by this item will be contained in our definitive proxy statement to be filed pursuant to Regulation 14A and is incorporated herein by reference.

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PART IV

Item 15. Exhibits and Financial Statement Schedules

(a)   (1) Financial Statements
 
    The following financial statements are included in Part II of this Annual Report on Form 10-K:
 
    Management’s Report on Internal Control over Financial Reporting
Independent Registered Public Accounting Firm Report — Audit of Financial Statements
Independent Registered Public Accounting Firm Report — Audit of Internal Control over Financial Reporting
Consolidated Balance Sheets – December 31, 2004 and 2003
Consolidated Statements of Operations for the years ended December 31, 2004, 2003 and 2002
Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2004, 2003 and 2002
Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002
Notes to Consolidated Financial Statements
 
    (2) Financial Statement Schedule
 
    Schedule II – Valuation and Qualifying Accounts for the years ended December 31, 2004, 2003 and 2002
 
    All other schedules are omitted because they are not applicable or the required information is included in the consolidated financial statements or notes thereto.
 
    (3) Exhibits
 
    The following exhibits are filed as part of this Annual Report on Form 10-K, or where indicated were previously filed and are hereby incorporated by reference:
 
    See the Index to Exhibits beginning on page E-1.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

         
  SUPERIOR ENERGY SERVICES, INC.
 
 
  By:   /s/ Terence E. Hall    
    Terence E. Hall   
    Chairman of the Board and Chief Executive Officer   
 

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

         
Signature   Title   Date
 
/s/ Terence E. Hall
Terence E. Hall
  Chairman of the Board and Chief Executive Officer (Principal Executive Officer)   March 15, 2005
/s/ Robert S. Taylor
Robert S. Taylor
  Executive Vice President, Treasurer and Chief Financial Officer (Principal Financial and Accounting Officer)   March 15, 2005
/s/ Enoch L. Dawkins
Enoch L. Dawkins
  Director   March 15, 2005
/s/ Ernest E. Howard, III
Ernest E. Howard, III
  Director   March 15, 2005
/s/ Richard A. Pattarozzi
Richard A. Pattarozzi
  Director   March 15, 2005
/s/ Justin L. Sullivan
Justin L. Sullivan
  Director   March 15, 2005

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Schedule II Valuation and Qualifying Accounts
Years Ended December 31, 2004, 2003 and 2002
(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, 2004:
                                       
Allowance for doubtful accounts
  $ 6,280     $ 2,970     $ 35     $ 921     $ 8,364  
Year ended December 31, 2003:
                                       
Allowance for doubtful accounts
  $ 4,617     $ 2,359     $     $ 696     $ 6,280  
Year ended December 31, 2002:
                                       
Allowance for doubtful accounts
  $ 4,057     $ 2,073     $ 133     $ 1,646     $ 4,617  

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Exhibit No.

  Description

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 of the Company (incorporated herein by reference to Exhibit 3.1 to the Company’s Form 8-K filed on November 15, 2004).
 
   
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
  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
  Amended and Restated 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), as amended by Second Amendment to Superior Energy Services, Inc. 1999 Stock Incentive Plan, effective as of December 7, 2004 (incorporated herein by reference to Exhibit 10.2 to the Company’s Form 8-K filed on December 20, 2004).

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Table of Contents

     
Exhibit No.

  Description

10.3
  Amended and Restated Credit Agreement dated as of August 13, 2003 among SESI, L.L.C. as borrower, the Company 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), as amended by First Amendment to Amended and Restated Credit Agreement, dated June 30, 2004, among SESI, L.L.C. as borrower, the Company as parent, Bank One, NA as agent, Wells Fargo Bank, 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 June 30, 2004), as amended by Second Amendment to Amended and Restated Credit Agreement, dated June 30, 2004, among SESI, L.L.C., as borrower, the Company as parent, Bank One, NA as agent, Wells Fargo Bank, N.A. as syndication agent, Whitney National Bank as documentation agent, and the lenders party thereto (incorporated herein by reference to Exhibit 99.1 to the Company’s Form 8-K filed on October 6, 2004).
 
   
10.4
  Employment Agreement between the Company and Terence E. Hall (incorporated herein by reference to the Company’s Annual Report on Form 10-K for the year ended December 31, 1999), as amended by Letter Agreement dated November 12, 2004 between the Company and Terence E. Hall (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K filed on November 15, 2004).
 
   
10.5
  Amended and Restated Superior Energy Services, Inc. 2002 Stock Incentive Plan (incorporated herein by reference to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003), as amended by First Amendment to Superior Energy Services, Inc. 2002 Stock Incentive Plan, effective as of December 7, 2004 (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K filed on December 20, 2004).
 
   
10.6
  Superior Energy Services, Inc.’s 2004 Directors’ Restricted Stock Units Plan (incorporated by reference to Appendix A to the Company’s Definitive Proxy Statement dated April 16, 2004).
 
   
10.7
  Stock Purchase Agreement, dated October 14, 2004, by and among the Company, First Reserve Fund VII, Limited Partnership and First Reserve Fund VIII, L.P. (incorporated herein by reference to Exhibit 99.1 to the Company’s Form 8-K filed on October 15, 2004).
 
   
10.8
  Form of Employment Agreement executed between the Company and each of its Chief Operating Officer and its Chief Financial Officer (incorporated herein by reference to Exhibit 10.1 to the Company’s Form 8-K filed on February 25, 2005).
 
   
10.9
  Form of Employment Agreement executed between the Company and each of its Executive Officers other than its Chairman and Chief Executive Officer, its Chief Operating Officer and its Chief Financial Officer (incorporated herein by reference to Exhibit 10.2 to the Company’s Form 8-K filed on February 25, 2005).

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Table of Contents

     
Exhibit No.

  Description

10.10*
  Third Amendment to Amended and Restated Credit Agreement, dated March 15, 2005, among SESI, L.L.C., as borrower, the Company as parent, Bank One, NA as agent, Wells Fargo Bank, N.A. as syndication agent, Whitney National Bank as documentation agent, and the lenders party thereto.
 
   
10.11*
  Superior Energy Services, Inc. Nonqualified Deferred Compensation Plan.
 
   
14.1
  Code of business ethics and conduct (incorporated herein by reference to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003).
 
   
21.1*
  Subsidiaries of the Company.
 
   
23.1*
  Consent of KPMG LLP.
 
   
23.2*
  Consent of DeGolyer and MacNaughton.
 
   
31.1*
  Officer’s certification pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as amended.
 
   
31.2*
  Officer’s certification pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as amended.
 
   
32.1*
  Officer’s certification pursuant to Section 1350 of Title 18 of the U.S. Code.
 
   
32.2*
  Officer’s certification pursuant to Section 1350 of Title 18 of the U.S. Code.


*   Filed herein

E-3

<PAGE>
                                                                   EXHIBIT 10.10


            THIRD AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT

      THIS THIRD AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT (this
"Amendment"), dated as of March 15, 2005, is among SESI, L.L.C., as Borrower,
SUPERIOR ENERGY SERVICES, INC., as Parent, BANK ONE, NA, as Agent (the "Agent"),
WELLS FARGO BANK, N.A., as Syndication Agent, WHITNEY NATIONAL BANK, as
Documentation Agent, and the Lenders party hereto, who agree as follows:

                                    RECITALS

      A. The Borrower, Agent and Lenders have heretofore executed an Amended and
Restated Credit Agreement dated as of August 14, 2003 (as amended, the "Credit
Agreement").

      B. The Borrower has requested that the Lenders permit the Borrower to
incur additional working capital indebtedness up to the aggregate amount of
$5,000,000.

      C. The Agent and Lenders are willing to accept the Borrower's request on
the terms and conditions set forth below.

      D. Capitalized terms used herein, and not otherwise defined herein, shall
have the meanings defined in the Credit Agreement.

      NOW, THEREFORE, in consideration of the mutual covenants and undertakings,
the parties hereby agree as follows:

                                    ARTICLE 1
                       AMENDMENTS TO THE CREDIT AGREEMENT

      1.1 Sections 6.11 (Indebtedness) of the Credit Agreement is hereby amended
to
 add a new Clause (xix) and to amend existing Clause (xix) to read as follows:

      (xix) Other secured Indebtedness not exceeding $5,000,000 in the aggregate
            principal amount outstanding at any one time.

      (xx)  The refinancing of any Indebtedness described in the foregoing
            Section 6.11(i) through (xix).

      1.2 Section 6.15(a)(iv) of the Credit Agreement (Liens) is hereby amended
to read as follows:

      (ix)  Other Liens that secure not more than $5,000,000 of Indebtedness,
            provided that such Liens do not encumber real estate, vessels or
            accounts.

      1.3 Except as specifically amended hereby, all of the remaining terms and
conditions of the Credit Agreement remain in full force and effect.


<PAGE>

                                    ARTICLE 2
                                     WAIVER

      2.1 At the Borrower's request, the undersigned Lenders hereby
retroactively grant to May 1, 2004 a one-time waiver of the provisions of
Sections 6.11 and 6.15 through the date hereof, to permit the Borrower to incur
other secured Indebtedness not exceeding $5,000,000 in the aggregate principal
amount outstanding at any one time.

                                    ARTICLE 3
                          ACKNOWLEDGMENT OF COLLATERAL

      3.1 Borrower hereby specifically reaffirms all of the Collateral
Documents.

                                    ARTICLE 4
                                  MISCELLANEOUS

      4.1 This Amendment may be executed in any number of separate counterparts,
and all of said counterparts taken together shall be deemed to constitute one in
the same instrument. This Amendment shall be effective as of the date first
written above upon execution by the Borrower, Parent and the Required Lenders.

                       [Rest of page intentionally blank]

                                     - 2 -


<PAGE>

      IN WITNESS WHEREOF, the Borrower, the Agent and the Lenders have executed
this Agreement as of the date first above written.

BORROWER:                               SESI, L.L.C.

                                        By: Superior Energy Services, Inc.
                                            Member Manager

                                            By: /s/ Robert S. Taylor
                                                --------------------------------
                                                Name: Robert S. Taylor
                                                Title: Chief Financial Officer

PARENT:                                 SUPERIOR ENERGY SERVICES, INC.

                                        By: /s/ Robert S. Taylor
                                            ------------------------------------
                                            Name: Robert S. Taylor
                                            Title: Chief Financial Officer

AGENT AND LENDER:                       BANK ONE, NA
                                        (Main Office Chicago)

                                        By: /s/ Steven D. Nance
                                            ------------------------------------
                                            Name: Steven D. Nance
                                            Title: Vice President

SYNDICATION AGENT AND LENDER:           WELLS FARGO BANK, N.A.

                                        By: /s/ Philip C. Lauinger III
                                            ------------------------------------
                                            Name: Philip C. Lauinger III
                                            Title: Vice President

DOCUMENTATION AGENT AND LENDER:         WHITNEY NATIONAL BANK

                                        By: /s/ Hollie L. Ercksen
                                            ------------------------------------
                                            Name: Hollie L. Ericksen
                                            Title: Vice President

                                     - 3 -


<PAGE>

LENDERS:                                PNC BANK, NATIONAL ASSOCIATION

                                        By: /s/ Vickie Leon
                                            ------------------------------------
                                            Name: Vickie Leon
                                            Title: Assistant Vice President

                                        NATEXIS BANQUES POPULAIRES

                                        By: /s/ Renaud d'Herbes
                                            ------------------------------------
                                            Name: Renaud d'Herbes
                                            Title: Vice President/Regional
                                                   Manager

                                        By: /s/ Daniel Payer
                                            ------------------------------------
                                            Name: Daniel Payer
                                            Title: Vice President

                                        HIBERNIA NATIONAL BANK

                                        By: /s/ Stephen Birnbaum
                                            ------------------------------------
                                            Name: Stephen Birnbaum
                                            Title: Vice President

                                        BANK OF SCOTLAND

                                        By: ____________________________________
                                            Name:
                                            Title:

                                        AMEGY BANK NA

                                        By: /s/ C. Ross Bartley
                                            ------------------------------------
                                            Name: C. Ross Bartley
                                            Title: Vice President

                                     - 4 -

<PAGE>
                                                                   EXHIBIT 10.11

                         SUPERIOR ENERGY SERVICES, INC.

                     NONQUALIFIED DEFERRED COMPENSATION PLAN

                                SEPTEMBER 1, 2004


<PAGE>

                                Table of Contents


<TABLE>
<CAPTION>
                                                                                                                    Page
                                                                                                                    ----
<S>                                                                                                                 <C>
ARTICLE I PURPOSE AND EFFECTIVE DATE..............................................................................    1
ARTICLE II DEFINITIONS............................................................................................    1
   2.01        Administrative Committee...........................................................................    1
   2.02        Base Salary........................................................................................    1
   2.03        Base Salary Deferral...............................................................................    1
   2.04        Beneficiary........................................................................................    1
   2.05        Board..............................................................................................    1
   2.06        Bonus Compensation.................................................................................    1
   2.07        Change of Control..................................................................................    1
   2.08        Code...............................................................................................    3
   2.09        Common Stock.......................................................................................    3
   2.10        Company............................................................................................    3
   2.11        Deferral Account...................................................................................    3
   2.12        Deferral Period....................................................................................    3
   2.13        Deferred Amount....................................................................................    3
   2.14        Designee...........................................................................................    4
   2.15        Disabled...........................................................................................    4
   2.16        Eligible Compensation..............................................................................    4
   2.17        ERISA..............................................................................................    4
   2.18        Form of Payment....................................................................................    4
   2.19        401(k) Plan........................................................................................    4
   2.20        Hardship Withdrawal................................................................................    4
   2.21        Hypothetical Investment Benchmark..................................................................    4
   2.22        Key Employee.......................................................................................    4
   2.23        Matching Contribution..............................................................................    5
   2.24        Participant........................................................................................    5
   2.25        Participation Agreement............................................................................    5
   2.26        Plan Year..........................................................................................    5
   2.27        Retirement.........................................................................................    5
   2.28        Termination of Employment..........................................................................    5
   2.29        Unforeseeable Emergency............................................................................    5
   2.30        Valuation Date.....................................................................................    5
ARTICLE III ADMINISTRATION........................................................................................    5
   3.01        Administrative Committee Duties....................................................................    5
   3.02        Claim Procedure....................................................................................    6
ARTICLE IV PARTICIPATION..........................................................................................    7
   4.01        Participation......................................................................................    7
   4.02        Contents of Participation Agreement................................................................    7
   4.03        Modification or Revocation of Election by Participant..............................................    8
ARTICLE V DEFERRED COMPENSATION...................................................................................    8
   5.01        Elective Deferred Compensation.....................................................................    8
   5.02        Vesting of Deferral Account........................................................................
    8
ARTICLE VI MAINTENANCE AND INVESTMENT OF ACCOUNTS.................................................................    8
</TABLE>


                                       i


<PAGE>

                               Table of Contents
                                  (continued)


<TABLE>
<CAPTION>
                                                                                                                    Page
                                                                                                                    ----
<S>                                                                                                                 <C>
   6.01        Maintenance of Accounts............................................................................    8
   6.02        Hypothetical Investment Benchmarks.................................................................    9
   6.03        Statement of Accounts..............................................................................    9
ARTICLE VII BENEFITS..............................................................................................    9
   7.01        Time and Form of Payment...........................................................................    9
   7.02        Matching Contribution..............................................................................    9
   7.03        Retirement........................................................................................    10
   7.04        In-Service Distributions and Effect of Termination of Employment..................................    10
   7.05        Death or Disability...............................................................................    10
   7.06        Hardship Withdrawals..............................................................................    11
   7.07        Change of Control.................................................................................    11
   7.08        Withholding of Taxes..............................................................................    11
   7.09        Acceleration or Deferral of Payment...............................................................    11
ARTICLE VIII BENEFICIARY DESIGNATION.............................................................................    12
   8.01        Beneficiary Designation...........................................................................    12
   8.02        No Beneficiary Designation........................................................................    12
ARTICLE IX AMENDMENT AND TERMINATION OF PLAN.....................................................................    12
   9.01        Amendment.........................................................................................    12
   9.02        Company's Right to Terminate......................................................................    12
ARTICLE X MISCELLANEOUS..........................................................................................    12
   10.01       Unfunded Plan.....................................................................................    12
   10.02       Nonassignability..................................................................................    12
   10.03       Payment to Spouse in Connection with Divorce......................................................    13
   10.04       Validity and Severability.........................................................................    13
   10.05       Governing Law.....................................................................................    13
   10.06       Employment Status.................................................................................    13
   10.07       Underlying Plans and Programs.....................................................................    13
   10.08       Severance.........................................................................................    13
</TABLE>


                                       ii


<PAGE>

                                    ARTICLE I
                           PURPOSE AND EFFECTIVE DATE

      The purpose of the Superior Energy Nonqualified Deferred Compensation Plan
("Plan") is to aid Superior Energy Services, Inc. ("Superior") and its
participating subsidiaries in retaining and attracting executive employees by
providing them with tax deferred savings opportunities. The Plan provides a
select group of management and highly compensated employees (within the meaning
of Sections 201(2), 301(a)(3) and 401(a)(1) of the Employee Retirement Income
Security Act of 1974, as amended (ERISA)) of Superior and its participating
subsidiaries with the opportunity to elect to defer receipt of specified
portions of compensation, and to have these deferred amounts treated as if
invested in specified hypothetical investment benchmarks. The Plan shall be
effective September 1, 2004, and deferral elections made hereunder shall be
effective on or after September 1, 2004.

                                   ARTICLE II
                                   DEFINITIONS

      For the purposes of this Plan, the following words and phrases shall have
the meanings indicated, unless the context clearly indicates otherwise:

      2.01 ADMINISTRATIVE COMMITTEE. "Administrative Committee" means the
committee appointed by the Compensation Committee of the Board, or by any
person(s) to whom the Compensation Committee of the Board has delegated the
power of appointment. As of the date effective date of the Plan, the persons
listed on Appendix B are members of the Administrative Committee.

      2.02 BASE SALARY. "Base Salary" means the base rate of cash compensation
paid by the Company to or for the benefit of a Participant for services rendered
or labor performed while a Participant, before any reduction for withholdings or
amounts deferred under the Plan or any other salary reduction program.

      2.03 BASE SALARY DEFERRAL. "Base Salary Deferral" means the amount of a
Participant's Base Salary that the Participant elects to have withheld on a
pre-tax basis from his Base Salary and credited to his Deferral Account pursuant
to, and subject to the limitations of, Section 4.02.

      2.04 BENEFICIARY. "Beneficiary" means the person, persons or entity
designated by the Participant to receive any benefits payable under the Plan
pursuant to Article VIII.

      2.05 BOARD. "Board" means the Board of Directors of Superior Energy
Services, Inc.

      2.06 BONUS COMPENSATION. "Bonus Compensation" means the cash bonus paid
annually near the end of the first quarter, after any withholdings or salary
reductions, but before reduction for amounts deferred under the Plan.

      2.07 CHANGE OF CONTROL. "Change of Control" means:

                                       1


<PAGE>

      (a) the acquisition by any person of beneficial ownership of 50% or more
of the outstanding shares of the Common Stock or 50% or more of the combined
voting power of the Company's then outstanding securities entitled to vote
generally in the election of directors; provided, however, that for purposes of
this subsection (a), the following acquisitions shall not constitute a Change of
Control:

            (1) any acquisition (other than a Business Combination (as defined
      below) which constitutes a Change of Control under Section 2.07(c) hereof)
      of Common Stock directly from the Company,

            (2) any acquisition of Common Stock by the Company,

            (3) any acquisition of Common Stock by any employee benefit plan (or
      related trust) sponsored or maintained by the Company or any corporation
      controlled by the Company, or

            (4) any acquisition of Common Stock by any corporation or other
      entity pursuant to a Business Combination that does not constitute a
      Change of Control under Section 2.07(c) hereof; or

      (b) individuals who, as of September 1, 2004, constituted the Board (the
"Incumbent Board") cease for any reason to constitute at least a majority of the
Board; provided, however, that any individual becoming a director subsequent to
such date whose election, or nomination for election by the Company's
stockholders, was approved by a vote of at least two-thirds of the directors
then comprising the Incumbent Board shall be considered a member of the
Incumbent Board, unless such individual's initial assumption of office occurs as
a result of an actual or threatened election contest with respect to the
election or removal of directors or other actual or threatened solicitation of
proxies or consents by or on behalf of a person other than the Incumbent Board;
or

      (c) consummation of a reorganization, share exchange, merger or
consolidation (including any such transaction involving any direct or indirect
subsidiary of the Company) or sale or other disposition of all or substantially
all of the assets of the Company (a "Business Combination"); provided, however,
that in no such case shall any such transaction constitute a Change of Control
if immediately following such Business Combination:

            (1) the individuals and entities who were the beneficial owners of
      the Company's outstanding Common Stock and the Company's voting securities
      entitled to vote generally in the election of directors immediately prior
      to such Business Combination have direct or indirect beneficial ownership,
      respectively, of more than 50% of the then outstanding shares of common
      stock, and more than 50% of the combined voting power of the then
      outstanding voting securities entitled to vote generally in the election
      of directors of the surviving or successor corporation, or, if applicable,
      the ultimate parent company thereof (the "Post-Transaction Corporation"),
      and

                                       2


<PAGE>

            (2) except to the extent that such ownership existed prior to the
      Business Combination, no person (excluding the Post-Transaction
      Corporation and any employee benefit plan or related trust of either the
      Company, the Post-Transaction Corporation or any subsidiary of either
      corporation) beneficially owns, directly or indirectly, 25% or more of the
      then outstanding shares of common stock of the corporation resulting from
      such Business Combination or 25% or more of the combined voting power of
      the then outstanding voting securities of such corporation, and

            (3) at least a majority of the members of the board of directors of
      the Post-Transaction Corporation were members of the Incumbent Board at
      the time of the execution of the initial agreement, or of the action of
      the Board providing for such Business Combination; or

      (d) approval by the stockholders of Superior of a complete liquidation or
dissolution of Superior.

For purposes of this Section 2.07, the term "person" shall mean a natural person
or entity, and shall also mean the group or syndicate created when two or more
persons act as a syndicate or other group (including, without limitation, a
partnership or limited partnership) for the purpose of acquiring, holding, or
disposing of a security, except that "person" shall not include an underwriter
temporarily holding a security pursuant to an offering of the security.

Notwithstanding this Section 2.07, a Change of Control will be deemed to occur
under such circumstances that the Secretary of the Treasury may prescribe via
regulations.

      2.08 CODE. "Code" means the Internal Revenue Code of 1986, as amended.
References to any provision of the Code or regulation (including a proposed
regulation) thereunder shall include any successor provisions or regulations.

      2.09 COMMON STOCK. "Common Stock" means the common stock of Superior
Energy Services, Inc.

      2.10 COMPANY. "Company" means Superior Energy Services, Inc., its
successors, any subsidiary, or affiliated organizations authorized by the
Compensation Committee of the Board to participate in the Plan and any
organization into which or with which Superior Energy Services, Inc. may merge
or consolidate or to which all or substantially all of its assets may be
transferred.

      2.11 DEFERRAL ACCOUNT. "Deferral Account" means the account maintained on
the books of the Company for each Participant pursuant to Article VI.

      2.12 DEFERRAL PERIOD. "Deferral Period" is defined in Section 4.02.

      2.13 DEFERRED AMOUNT. "Deferred Amount" is defined in Section 4.02.

                                       3


<PAGE>

      2.14 DESIGNEE. "Designee" means the individual(s) to whom the
Administrative Committee has delegated the authority to take action under the
Plan. Wherever Administrative Committee is referenced in the Plan, it shall be
deemed to also refer to Designee.

      2.15 DISABLED. A Participant shall be considered Disabled if the
Participant:

            (a) is unable to engage in any substantial gainful activity by
      reason of any medically determinable physical or mental impairment which
      can be expected to result in death or can be expected to last for a
      continuous period of not less than 12 months, or

            (b) is, by reason of any medically determinable physical or mental
      impairment which can be expected to result in death or can be expected to
      last for a continuous period of not less than 12 months, receiving income
      replacement benefits for a period of not less than 3 months under an
      accident and health plan covering employees of the Participant's employer.

      2.16 ELIGIBLE COMPENSATION. "Eligible Compensation" means any Base Salary
and Bonus Compensation otherwise payable with respect to a Plan Year. Eligible
Compensation does not include expense reimbursements, any form of noncash
compensation, stock-based plans, or benefits.

      2.17 ERISA. "ERISA" means the Employee Retirement Income Security Act of
1974, as amended.

      2.18 FORM OF PAYMENT. "Form of Payment" means payment in one lump sum or
in substantially equal annual installments of 2 to 15 years.

      2.19 401(k) PLAN. "401(k) Plan" means the Superior Energy 401(k) Plan, as
amended.

      2.20 HARDSHIP WITHDRAWAL. "Hardship Withdrawal" means the early payment of
all or part of the balance in a Deferral Account(s) in the event of an
Unforeseeable Emergency.

      2.21 HYPOTHETICAL INVESTMENT BENCHMARK. "Hypothetical Investment
Benchmark" means the phantom investment benchmarks which are used to measure the
return credited to a Participant's Deferral Account.

      2.22 KEY EMPLOYEE. "Key Employee" shall have the meaning set forth in
Section 416(i) of the Code, as adjusted by the Secretary of the Treasury for
cost-of-living changes. As of the Effective Date of the Plan, a Key Employee is:

            (a) an officer of the Company having annual compensation from the
      Company of greater than $130,000;

            (b) an owner of 1% or more of the Company having annual compensation
      from the Company greater than $150,000; or

            (c) an owner of 5% or more of the Company.

                                       4


<PAGE>

      2.23 MATCHING CONTRIBUTION. "Matching Contribution" means the amount of
annual matching contribution, if any, that the Company makes to the Plan.

      2.24 PARTICIPANT. "Participant" means any individual who is eligible to
participate in this Plan, and who elects to participate by filing a
Participation Agreement as provided in Article IV.

      2.25 PARTICIPATION AGREEMENT. "Participation Agreement" means an agreement
filed by a Participant in accordance with Article IV.

      2.26 PLAN YEAR. "Plan Year" means a twelve-month period beginning January
1 and ending the following December 31. The initial Plan Year shall be the
period beginning September 1, 2004, and ending the following December 31.

      2.27 RETIREMENT. "Retirement" means retirement of a Participant from the
Company after attaining age 65 or age 55 with at least five years of service (in
accordance with the method of determining years of service adopted by the
Company).

      2.28 TERMINATION OF EMPLOYMENT. "Termination of Employment" means the
cessation of a Participant's services as a full-time employee of the Company for
any reason other than Retirement.

      2.29 UNFORESEEABLE EMERGENCY. "Unforeseeable Emergency" means a severe
financial hardship to the Participant resulting from a sudden and unexpected
illness or accident of the Participant, the Participant's Spouse, or a dependent
(as defined in Section 152(a) of the Code) of the Participant, loss of the
Participant's property due to casualty, or other similar extraordinary and
unforeseeable circumstances arising as a result of events beyond the control of
the Participant.

      2.30 VALUATION DATE. "Valuation Date" means the last calendar date when
the New York Stock Exchange was open, or such other date as the Administrative
Committee in its sole discretion may determine.

                                   ARTICLE III
                                 ADMINISTRATION

      3.01 ADMINISTRATIVE COMMITTEE DUTIES. This Plan shall be administered by
the Administrative Committee. A majority of the members of the Administrative
Committee shall constitute a quorum for the transaction of business. All
resolutions or other action taken by the Administrative Committee shall be by a
vote of a majority of its members present at any meeting or, without a meeting,
by an instrument in writing signed by all its members. Members of the
Administrative Committee may participate in a meeting of such committee by means
of a conference telephone or similar communications equipment that enables all
persons participating in the meeting to hear each other, and such participation
in a meeting shall constitute presence in person at the meeting and waiver of
notice of such meeting.

      The Administrative Committee shall be responsible for the administration
of this Plan and shall have all powers necessary to administer this Plan,
including discretionary authority to

                                       5


<PAGE>

determine eligibility for benefits and to decide claims under the terms of this
Plan, except to the extent that any such powers are vested in any other person
administering this Plan by the Administrative Committee. The Administrative
Committee may from time to time establish rules for the administration of this
Plan, and it shall have the exclusive right to interpret this Plan and to decide
any matters arising in connection with the administration and operation of this
Plan. All rules, interpretations and decisions of the Administrative Committee
shall be conclusive and binding on the Company, Participants and Beneficiaries.

      The Administrative Committee shall be responsible for determining in the
first instance issues related to eligibility, Hypothetical Investment
Benchmarks, distribution of Deferred Amounts, determination of account balances,
crediting of hypothetical earnings and debiting of hypothetical losses and of
distributions, in-service withdrawals, deferral elections and any other duties
concerning the day-to-day operation of this Plan. The Administrative Committee
may designate one of its members as a chairperson and may retain and supervise
outside providers, third party administrators, record keepers and professionals
(including in-house professionals) to perform any or all of the duties delegated
to it hereunder.

      Neither a member of the Board nor any member of the Administrative
Committee shall be liable for any act or action hereunder, whether of omission
or commission, by any other member or employee or by any agent to whom duties in
connection with the administration of this Plan have been delegated or for
anything done or omitted to be done in connection with this Plan. The
Administrative Committee shall keep records of all of its proceedings and shall
keep records of all payments made to Participants or Beneficiaries and payments
made for expenses or otherwise.

      The Company shall, to the fullest extent permitted by law, indemnify each
director, officer or employee of the Company (including the heirs, executors,
administrators and other personal representatives of such person) and each
member of the Administrative Committee against expenses (including attorneys'
fees), judgments, fines, amounts paid in settlement, actually and reasonably
incurred by such person in connection with any threatened, pending or actual
suit, action or proceeding (whether civil, criminal, administrative or
investigative in nature or otherwise) in which such person may be involved by
reason of the fact that he or she is or was serving this Plan in any capacity at
the request of the Company or Administrative Committee.

      Any expense incurred by the Company or the Administrative Committee
relative to the administration of this Plan shall be paid by the Company and/or
may be deducted from the Deferral Accounts of the Participants, as determined by
the Administrative Committee.

      3.02 CLAIM PROCEDURE. If a Participant or Beneficiary makes a written
request alleging a right to receive payments under this Plan or alleging a right
to receive an adjustment in benefits being paid under this Plan, such actions
shall be treated as a claim for benefits. All claims for benefits under this
Plan shall be sent to the Administrative Committee. If the Administrative
Committee determines that any individual who has claimed a right to receive
benefits, or different benefits, under this Plan is not entitled to receive all
or any part of the benefits claimed, the Administrative Committee shall inform
the claimant in writing of such determination and the reasons therefor in terms
calculated to be understood by the claimant. The notice shall be sent within 90
days of the claim unless the Administrative Committee determines

                                       6


<PAGE>

that additional time, not exceeding 90 days, is needed and so notifies the
Participant. The notice shall make specific reference to the pertinent Plan
provisions on which the denial is based, and shall describe any additional
material or information that is necessary. Such notice shall, in addition,
inform the claimant of the procedure that the claimant should follow to take
advantage of the review procedures set forth below in the event the claimant
desires to contest the denial of the claim. The claimant may within 90 days
thereafter submit in writing to the Administrative Committee a notice that the
claimant contests the denial of his or her claim and desires a further review by
the Administrative Committee. The Administrative Committee shall within 60 days
thereafter review the claim and authorize the claimant to review pertinent
documents and submit issues and comments relating to the claim to the
Administrative Committee. The Administrative Committee will render a final
decision on behalf of the Company with specific reasons therefor in writing and
will transmit it to the claimant within 60 days of the written request for
review, unless the Administrative Committee determines that additional time, not
exceeding 60 days, is needed, and so notifies the Participant.

                                   ARTICLE IV
                                  PARTICIPATION

      4.01 PARTICIPATION. Participation in the Plan shall be limited to
executives who (i) are included on a list of eligible employees that the
Administrative Committee shall establish and revise from time to time and that
is approved by the Compensation Committee of the Board; and (ii) elect to
participate in this Plan by filing a Participation Agreement with the
Administrative Committee or its designee. A Participation Agreement must be
filed prior to the December 15th immediately preceding the Plan Year for which
it is effective. The Administrative Committee shall have the discretion to
specify the contents of Participation Agreements and to establish special
deadlines regarding the filing of Participation Agreements. An election made by
a newly eligible Participant may be made effective for the current taxable year
only if such election is made not more than 30 days after the Participant
becomes eligible to participate in the Plan.

      4.02 CONTENTS OF PARTICIPATION AGREEMENT. Subject to Article VII, each
Participation Agreement shall set forth: (i) the amount of Eligible Compensation
for the Plan Year or performance period to which the Participation Agreement
relates that is to be deferred under the Plan (the "Deferred Amount"), expressed
as either a dollar amount or a percentage of the Base Salary and Bonus
Compensation for such Plan Year or performance period; provided that the maximum
Deferred Amount for any Plan Year shall not exceed 75% of Base Salary and 100%
of Bonus Compensation; (ii) the period after which payment of the Deferred
Amount is to be made or begin to be made (the "Deferral Period"), and (iii) the
form in which payments are to be made, which may be a lump sum or in
substantially equal annual installments of 2 to 15 years. The Deferral Period
may be expressed as ending on a specified date (not less than three years from
the year of the election), upon the occurrence of an event (such as a
Participant's Retirement or Termination of Employment), or in accordance with
such other terms and options that may be set forth in the Participation
Agreement. The Deferral Period cannot end later than the year in which the
Participant attains age 65 (unless the Participant remains employed by the
Company when he/she attains age 65, in which case the Deferral Period will end
upon the Participant's Retirement or Termination of Employment with the
Company).

                                       7


<PAGE>

      4.03 MODIFICATION OR REVOCATION OF ELECTION BY PARTICIPANT.

            (a) A Participant may not change the amount of his Base Salary
      Deferrals during a Plan Year. However, a Participant may discontinue a
      Base Salary Deferral election at any time by filing, on such forms and
      subject to such limitations and restrictions as the Administrative
      Committee may prescribe in its discretion, a revised Participation
      Agreement with the Administrative Committee. If approved by the
      Administrative Committee, revocation shall take effect as of the first
      payroll period next following its filing. If a Participant discontinues a
      Base Salary Deferral election during a Plan Year, he will not be permitted
      to elect to make Base Salary Deferrals again until 12 months from the date
      of discontinuance. In accordance with Section 4.01 of the Plan, such
      election to resume deferrals shall not be effective until the following
      Plan Year. A Participant cannot revoke an election to defer Bonus
      Compensation.

            (b) A Participant may make a one-time election to change the time or
      form of his/her payment from the Plan as set forth in an existing
      Participation Agreement, but such a change must include the lengthening of
      the Deferral Period by no less than five years from the original payment
      date under the Participation Agreement (as in effect before such
      amendment). Such amended Participation Agreement must be filed with the
      Administrative Committee or its designee at least 12 months prior to the
      date of the first scheduled payment under the Participation Agreement (as
      in effect before such amendment). Under no circumstances may a
      Participant's Participation Agreement be retroactively entered into,
      modified or revoked.

                                   ARTICLE V
                              DEFERRED COMPENSATION

      5.01 ELECTIVE DEFERRED COMPENSATION. The Deferred Amount of a Participant
with respect to each Plan Year of participation in the Plan shall be credited by
the Administrative Committee to the Participant's Deferral Account as and when
such Deferred Amount would otherwise have been paid to the Participant. To the
extent that the Company is required to withhold any taxes or other amounts from
the Deferred Amount pursuant to any state, Federal or local law, such amounts
shall be taken out of other compensation eligible to be paid to the Participant
that is not deferred under this Plan.

      5.02 VESTING OF DEFERRAL ACCOUNT. Except as provided in Section 7.02, a
Participant shall be 100% vested in his/her Deferral Account at all times.

                                   ARTICLE VI
                     MAINTENANCE AND INVESTMENT OF ACCOUNTS

      6.01 MAINTENANCE OF ACCOUNTS. Separate Deferral Accounts shall be
maintained for each Participant. More than one Deferral Account may be
maintained for a Participant as necessary to reflect (a) various Hypothetical
Investment Benchmarks and/or (b) separate Participation Agreements specifying
different Deferral Periods and/or forms of payment. A Participant's Deferral
Account(s) shall be utilized solely as a device for the measurement and
determination of the amounts to be paid to the Participant pursuant to this
Plan, and shall not

                                       8


<PAGE>

constitute or be treated as a trust fund of any kind. The Administrative
Committee shall determine the balance of each Deferral Account, as of each
Valuation Date, by adjusting the balance of such Deferral Account as of the
immediately preceding Valuation Date to reflect changes in the value of the
deemed investments thereof, credits and debits pursuant to Section 5.01 and
Section 6.02 and distributions pursuant to Article VII with respect to such
Deferral Account since the preceding Valuation Date.

      6.02 HYPOTHETICAL INVESTMENT BENCHMARKS. Each Participant shall be
entitled to direct the manner in which his/her Deferral Accounts will be deemed
to be invested by selecting among the Hypothetical Investment Benchmarks
specified in Appendix A hereto, as amended by the Administrative Committee from
time to time, and in accordance with such rules, regulations and procedures as
the Administrative Committee may establish from time to time. Notwithstanding
anything to the contrary herein, earnings and losses based on a Participant's
investment elections shall begin to accrue as of the date such Participant's
Deferral Amounts are credited to his/her Deferral Accounts.

      6.03 STATEMENT OF ACCOUNTS. The Administrative Committee shall submit to
each Participant quarterly statements of his/her Deferral Account(s) in such
form as the Administrative Committee deems desirable, setting forth the balance
to the credit of such Participant in his/her Deferral Account(s) as of the end
of the most recently completed quarter.

                                   ARTICLE VII
                                    BENEFITS

      7.01 TIME AND FORM OF PAYMENT. At the end of the Deferral Period for each
Deferral Account, the Company shall pay to the Participant the balance of such
Deferral Account at the time or times elected by the Participant in the
applicable Participation Agreement; provided that if the Participant has elected
to receive payments from a Deferral Account in a lump sum, the Company shall pay
the balance in such Deferral Account (determined as of the most recent Valuation
Date preceding the end of the Deferral Period) in a lump sum in cash as soon as
practicable after the end of the Deferral Period. If the Participant has elected
to receive payments from a Deferral Account in installments, the Company shall
make annual cash payments from such Deferral Account, each of which shall
consist of an amount equal to (i) the balance of such Deferral Account as of the
most recent Valuation Date preceding the payment date times (ii) a fraction, the
numerator of which is one and the denominator of which is the number of
remaining installments (including the installment being paid). The first such
installment shall be paid as soon as practicable after the end of the Deferral
Period and each subsequent installment shall be paid on or about the anniversary
of such first payment. Each such installment shall be deemed to be made on a pro
rata basis from each of the different deemed investments of the Deferral Account
(if there is more than one such deemed investment).

      7.02 MATCHING CONTRIBUTION. Each Participant who elects to make deferrals
of Eligible Compensation to the Plan may receive a Matching Contribution equal
to the percentage of that Participant's Deferred Amount, if any, declared by the
Compensation Committee of the Board. Matching Contributions will be credited to
the Participant's Deferral Account as of the date Company matching contributions
would be contributed to the Participant's Superior Energy 401(k) Plan account
and shall follow the Participant's Hypothetical Investment Benchmarks for

                                       9


<PAGE>

the deferral of the Eligible Compensation to which it relates. The amount of the
Matching Contribution may vary from payroll period to payroll period throughout
the Plan Year, may be based on a formula that takes into account a Participant's
overall compensation, and otherwise may be subject to maximum or minimum
limitations. The Matching Contribution shall be invested among the same
Hypothetical Investment Benchmarks as defined in Section 6.02 in the same
proportion as the elections made by the Participant governing the deferrals of
the Participant. The Matching Contribution shall be distributed to the
Participant according to the election made by the Participant governing his/her
deferrals and will vest according to the provisions governing matching
contributions in the 401(k) Plan. Any Matching Contributions that are not vested
when Matching Contributions are to be distributed to the Participant shall be
forfeited to the Company.

      7.03 RETIREMENT. Subject to Section 7.01 and Section 7.06 hereof, if a
Participant has elected to have the balance of his/her Deferral Account
distributed upon Retirement, the account balance of the Participant (determined
as of the most recent Valuation Date) shall be distributed upon Retirement in
installments or a lump sum in accordance with the Plan and as elected in the
Participation Agreement, and such payment(s) shall commence upon Termination of
Employment. Notwithstanding this Section 7.03, a Participant who is a Key
Employee shall not be entitled to take a distribution of the balance of his
Deferral Account(s) on account of his/her Retirement for a period of 6 months
following such Retirement or Termination of Employment, unless such balance is
distributable pursuant to another provision of the Plan (e.g. due to
Disability).

      7.04 IN-SERVICE DISTRIBUTIONS AND EFFECT OF TERMINATION OF EMPLOYMENT.
Subject to Section 7.01 and Section 7.06 hereof, if a Participant has elected to
defer Eligible Compensation under the Plan for a stated number of years, the
account balance of the Participant (determined as of the most recent Valuation
Date preceding such Deferral Period) shall be distributed in installments or a
lump sum in accordance with the Plan and as elected in the Participation
Agreement. Notwithstanding the previous sentence, a Participant may specify in
his/her Participation Agreement that his/her Deferral Account shall be
distributed to him/her in a lump sum upon Termination of Employment, if such
termination occurs before the elected date. Notwithstanding this Section 7.04, a
Participant who is a Key Employee shall not be entitled to take a distribution
of the balance of his Deferral Account(s) on account of his/her Termination of
Employment for a period of 6 months following such Termination of Employment,
unless such balance is distributable pursuant to another provision of the Plan
(e.g. due to Disability).

      7.05 DEATH OR DISABILITY. Notwithstanding the provisions of Section 7.03
and 7.04 hereof and any Participation Agreement, if a Participant dies or
becomes Disabled prior to receiving full payment of his/her Deferral Account(s),
the Company shall pay the remaining balance of his/her Deferral Account
(determined as of the most recent Valuation Date preceding such event) to the
Participant or the Participant's Beneficiary or Beneficiaries (as the case may
be) in a lump sum in cash as soon as practicable following the occurrence of
such event, unless the Administrative Committee in its sole discretion
determines otherwise. Subject to Section 6.02 hereof, the amount distributable
under the preceding sentence of this Section 7.05 shall be based on the
Participant's investment elections.

                                       10


<PAGE>

      7.06 HARDSHIP WITHDRAWALS. Notwithstanding the provisions of Section 7.01
and any Participation Agreement, a Participant shall be entitled to early
payment of all or part of the balance in his/her Deferral Account(s) in the
event of an Unforeseeable Emergency, in accordance with this Section 7.06. A
distribution pursuant to this Section 7.06 may only be made to the extent
reasonably needed to satisfy the Unforeseeable Emergency need, and may not be
made if such need is or may be relieved (i) through reimbursement or
compensation by insurance or otherwise, (ii) by liquidation of the Participant's
assets to the extent such liquidation would not itself cause severe financial
hardship, or (iii) by cessation of participation in the Plan. An application for
an early payment under this Section 7.06 shall be made to the Administrative
Committee in such form and in accordance with such procedures as the
Administrative Committee shall determine from time to time. The determination of
whether and in what amount and form a distribution will be permitted pursuant to
this Section 7.06 shall be made by the Administrative Committee.

      7.07 CHANGE OF CONTROL. In the event of a Change of Control that was
recommended for approval to the shareholders by the Board, no immediate special
payment shall be made to any Participant and the terms and conditions of the
Plan shall remain in full force and effect. Notwithstanding anything contained
in this Plan to the contrary, upon a Hostile Change of Control, the Company
shall immediately pay to each Participant in a lump sum in cash the balance in
his/her Deferral Account(s) (determined as of the most recent Valuation Date
preceding the Change of Control). Hostile Change of Control is defined as a
Change of Control of the Company that was not recommended for approval to the
shareholders by the Board. Notwithstanding this Section 7.07, if a Participant
is subject to the requirements of Section 16(a) of the Securities Exchange Act
of 1934, the Participant's balance in his Deferral Account(s) shall not be
distributed on account of a Change in Control prior to the date that is one year
after the date of the Change of Control, unless such balance is distributable
pursuant to another provision of the Plan.

      7.08 WITHHOLDING OF TAXES. Notwithstanding any other provision of this
Plan, the Company shall withhold from payments made hereunder any amounts
required to be so withheld by any applicable law or regulation.

      7.09 ACCELERATION OR DEFERRAL OF PAYMENT. A Participant shall not have no
right to compel any accelerated payment of amounts due to a Participant, except
as provided in Sections 7.05, 7.06 and 7.07. The Company reserves the right to
defer the payment of some or all of the amounts due to a Participant in a given
year if the Plan Administrator determines that the payment(s) due to a
Participant in such year would result in negative tax consequences to the
Company as a result of exceeding the limit set forth in Code Section 162(m). The
preceding sentence shall not apply if there is a Hostile Change of Control, as
described in Section 7.07. Notwithstanding the terms of any Participation
Agreement, the Plan may refuse to accept Deferral Amounts and may distribute
Deferral Amounts to Participants at any time, if the Administrative Committee
determines that such actions are required in order to comply with applicable
law.

                                       11


<PAGE>

                                  ARTICLE VIII
                             BENEFICIARY DESIGNATION

      8.01 BENEFICIARY DESIGNATION. Each Participant shall have the right, at
any time, to designate any person, persons or entity as his Beneficiary or
Beneficiaries. A Beneficiary designation shall be made, and may be amended, by
the Participant by filing a written designation with the Administrative
Committee, on such form and in accordance with such procedures as the
Administrative Committee shall establish from time to time.

      8.02 NO BENEFICIARY DESIGNATION. If a Participant fails to designate a
Beneficiary as provided above, or if all designated Beneficiaries predecease the
Participant, then the Participant shall be deemed to have designated the
surviving spouse of the Participant as the designated Beneficiary. If the
Participant dies without a designated Beneficiary (or spouse as the deemed
designated Beneficiary), then the Participant's Beneficiary shall be deemed to
be the Participant's estate.

                                   ARTICLE IX
                        AMENDMENT AND TERMINATION OF PLAN

      9.01 AMENDMENT. The Compensation Committee of the Board, or any person(s)
to whom such committee has delegated the right to amend the Plan, may at any
time amend this Plan in whole or in part, provided, however, that no amendment
shall be effective to decrease the balance in any Deferral Account as accrued at
the time of such amendment.

      9.02 COMPANY'S RIGHT TO TERMINATE. The Board may at any time terminate the
Plan with respect to future Participation Agreements or future contributions.
The Board may also terminate the Plan in its entirety at any time for any
reason. Upon any such termination, distribution of amounts due to Participants
shall be made in accordance with Article VII of this Plan.

                                    ARTICLE X
                                  MISCELLANEOUS

      10.01 UNFUNDED PLAN. This Plan is intended to be an unfunded plan
maintained primarily for the purpose of providing deferred compensation for a
select group of management or highly compensated employees, within the meaning
of Sections 201, 301 and 401 of ERISA. All payments pursuant to the Plan shall
be made from the general funds of the Company and no special or separate fund
shall be established or other segregation of assets made to assure payment. No
Participant or other person shall have under any circumstances any interest in
any particular property or assets of the Company as a result of participating in
the Plan. Notwithstanding the foregoing, the Company may (but shall not be
obligated to) create one or more grantor trusts, the assets of which are subject
to the claims of the Company's creditors, to assist it in accumulating funds to
pay its obligations under the Plan. Participants shall have no right to compel
the investment of any amounts deposited in any such trust(s).

      10.02 NONASSIGNABILITY. Except as specifically set forth in the Plan with
respect to the designation of Beneficiaries, neither a Participant nor any other
person shall have any right to commute, sell, assign, transfer, pledge,
anticipate, mortgage or otherwise encumber, transfer,

                                       12


<PAGE>

hypothecate or convey in advance of actual receipt the amounts, if any, payable
hereunder, or any part thereof, which are, and all rights to which are,
expressly declared to be unassignable and non-transferable. No part of the
amounts payable shall, prior to actual payment, be subject to seizure or
sequestration for the payment of any debts, judgments, alimony or separate
maintenance owed by a Participant or any other person, nor be transferable by
operation of law in the event of a Participant's or any other person's
bankruptcy or insolvency.

      10.03 PAYMENT TO SPOUSE IN CONNECTION WITH DIVORCE. Section 10.02 of the
Plan to the contrary notwithstanding, if a Participant should become divorced, a
portion of his Deferral Account(s) may be assigned to his former spouse by order
of the court having jurisdiction over the divorce. Upon receipt of a certified
copy of such an order, and upon determining that the order assigns a
determinable amount or percentage of the Participant's Deferral Account(s) to
the former spouse, the Administrative Committee shall give effect to the order,
so that when a benefit with respect to the Participant becomes payable (to the
Participant or the Participant's Beneficiary) the former spouse will receive the
amount or percentage (as stated in the order) of the benefit determined under
Article VII of the Plan. If the Administrative Committee determines that the
court order does not set out a determinable amount or percentage, or for some
other reason determines that the order cannot be enforced as written, the
Administrative Committee shall notify the Participant and the former spouse of
the objections to giving effect to the order.

      10.04 VALIDITY AND SEVERABILITY. The invalidity or unenforceability of any
provision of this Plan shall not affect the validity or enforceability of any
other provision of this Plan, which shall remain in full force and effect, and
any prohibition or unenforceability in any jurisdiction shall not invalidate or
render unenforceable such provision in any other jurisdiction.

      10.05 GOVERNING LAW. The validity, interpretation, construction and
performance of this Plan shall in all respects be governed by the laws of the
State of Louisiana, without reference to principles of conflict of law, except
to the extent preempted by federal law.

      10.06 EMPLOYMENT STATUS. This Plan does not constitute a contract of
employment or impose on the Participant or the Company any obligation for the
Participant to remain an employee of the Company or change the status of the
Participant's employment or the policies of the Company and its affiliates
regarding termination of employment.

      10.07 UNDERLYING PLANS AND PROGRAMS. Nothing in this Plan shall prevent
the Company from modifying, amending or terminating the compensation or the
plans and programs pursuant to which cash awards are earned and which are
deferred under this Plan.

      10.08 SEVERANCE. Notwithstanding anything to the contrary herein, the
Administrative Committee may, in its sole and exclusive discretion, determine
that the Deferral Account of a Participant who has incurred a Termination of
Employment and who receives or will receive severance payments from the Company
shall be paid in installments, at such intervals as the Administrative Committee
may decide.

                                       13


<PAGE>

      IN WITNESS HEREOF, the Plan is hereby executed on the 1st day of
September, 2004, to be effective September 1, 2004, unless stated otherwise.

WITNESSES                                 SUPERIOR ENERGY SERVICES, INC.

/s/ Ross A. Burkenstock                   By: /s/ Robert S. Taylor
-----------------------------------           ----------------------------------

/s/ Danny R. Young                        Title: Chief Financial Officer
-----------------------------------

                                       14


<PAGE>

                                   APPENDIX A
                              INVESTMENT BENCHMARKS

MONY Series Money Market Portfolio

MONY Series Intermediate Term Bond Portfolio

Fidelity VIP II Asset Manager

T. Rowe Price Equity Income Portfolio

Dreyfus Stock Index Portfolio (S & P 500)

Fidelity VIP II Contrafund (Initial Class)

Alger American Mid Cap Growth

Dreyfus Small Company Portfolio

Janus AS Capital Appreciation

T. Rowe Price International Stock Portfolio

                                      A-1


<PAGE>

                                   APPENDIX B
                            ADMINISTRATIVE COMMITTEE

The members of the Plan's Administrative Committee are as follows:

Donna Cummins
Wayne Robertson
Greg Rosenstein
Robert Taylor
Danny Young

                                      B-1

exv21w1
 

EXHIBIT 21.1

SUPERIOR ENERGY SERVICES, INC.
List of Subsidiaries*

     
    STATE OF JURISDICTION OF
NAME   INCORPORATION OR ORGANIZATION
1105 Peters Road, L.L.C.
  Louisiana
 
   
Ace Rental Tools, L.L.C.
  Louisiana
 
   
Blowout Tools, Inc.
  Texas
 
   
Concentric Pipe and Tool Rentals, L.L.C.
  Louisiana
 
   
Connection Technology, L.L.C.
  Louisiana
 
   
Environmental Treatment Team, L.L.C.
  Louisiana
 
   
F & F Wireline Services, L.L.C.
  Louisiana
 
   
Fastorq, L.L.C.
  Louisiana
 
   
H.B Rentals, L.C.
  Louisiana
 
   
International Snubbing Services, L.L.C.
  Louisiana
 
   
Lamb Energy Services, L.L.C.
  Delaware
 
   
Oil Stop, L.L.C.
  Louisiana
 
   
Premier Oilfield Rentals Limited
  Scotland
 
   
Production Management Industries, L.L.C.
  Louisiana
 
   
SESI, L.L.C.
  Delaware
 
   
SPN Resources, LLC
  Louisiana
 
   
Southeast Australian Services Pty., Ltd.
  Australia
 
   
Stabil Drill Specialties, L.L.C.
  Louisiana
 
   
Sub-Surface Tools, L.L.C.
  Louisiana
 
   
Superior Energy Services, L.L.C.
  Louisiana
 
   
Superior Energy Services de Venezuela, C.A.
  Venezuela
 
   
Superior Energy Services Trinidad, Ltd.
  Trinidad/Tobago
 
   
Superior Inspection Services, Inc.
  Louisiana

 


 

     
    STATE OF JURISDICTION OF
NAME   INCORPORATION OR ORGANIZATION
Tong Specialty, L.L.C.
  Louisiana
 
   
Universal Fishing and Rental Tools, Inc.
  Louisiana
 
   
Wild Well Control, Inc.
  Texas
 
   
Workstrings, L.L.C.
  Louisiana


*   Names of particular subsidiaries have been omitted from the above list because, considered in the aggregate, they would not constitute, as of the end of the year covered by this report, a “significant subsidiary” as that term is defined in Rule 1.02(w) of Regulation S-X under the Securities Exchange Act of 1934.

 

<PAGE>


                                                                    EXHIBIT 23.1

            Consent of Independent Registered Public Accounting Firm

The Board of Directors
Superior Energy Services, Inc.:

We consent to incorporation by reference in Registration Statements No.
333-35286 on Form S-3 and No. 333-12175, No. 333-43421, No. 333-33758, No.
333-101211 and No. 333-116078 on Form S-8 of Superior Energy Services, Inc. of
our reports dated March 11, 2005, with respect to the consolidated balance
sheets of Superior Energy Services, Inc. and subsidiaries as of December 31,
2004 and 2003, 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, 2004, the related consolidated financial statement
schedule, management's assessment of the effectiveness of internal control over
financial reporting as of December 31, 2004, and the effectiveness of internal
control over financial reporting as of December 31, 2004, which reports appear
in the December 31, 2004 annual report on Form 10-K of Superior Energy
Services, Inc.


/s/ KPMG LLP


New Orleans, Louisiana
March 11, 2005




<PAGE>
                                                                    EXHIBIT 23.2


                            DeGOLYER AND MacNAUGHTON
                        4925 Greenville Avenue, Suite 400
                                One Energy Square
                               Dallas, Texas 75206

                                 March 10, 2005

Superior Energy Services, Inc.
1105 Peters Road
Harvey, LA 70058

Gentlemen:

      We hereby consent to the reference to our firm and to the incorporation of
the estimates contained in our "Appraisal Report as of December 31, 2004 on
Certain Properties owned by SPN Resources" (our Report) in the Annual Report on
Form 10-K of Superior Energy Services, Inc. for the year ended in December 31,
2004, as well as in the "Notes to the Consolidated Financial Statements"
included therein. SPN Resources is a wholly owned subsidiary of Superior Energy
Services, Inc. In addition, we hereby consent to the incorporation by reference
of such reference to our firm and to our Report in Superior Energy Services,
Inc.'s Registration Statement on Form S-3 to be filed in March 2005 and the
previously filed Registration Statements on Form S-3 (Registration No.
333-35286) and on Form S-8 (Registration Nos. 333-116078, 333-101211, 333-33758,
333-43421, and 333-12175).

                                                    Very truly yours,

                                                    /s/ DeGOLYER and MacNAUGHTON

                                                    DeGOLYER and MacNAUGHTON



<PAGE>


                                                                    EXHIBIT 31.1

                            CERTIFICATION PURSUANT TO
    RULES 13A-14(a) AND 15D-14(a) UNDER THE SECURITIES EXCHANGE ACT OF 1934,
                                   AS AMENDED

         I, Terence E. Hall, Chairman of the Board and Chief Executive Officer
of Superior Energy Services, Inc., certify that:

1.       I have reviewed this annual report on Form 10-K of Superior Energy
         Services, Inc.;

2.       Based on my knowledge, this report does not contain any untrue
         statement of a material fact or omit to state a material fact necessary
         to make the statements made, in light of the circumstances under which
         such statements were made, not misleading with respect to the period
         covered by this report;

3.       Based on my knowledge, the financial statements, and other financial
         information included in this report, fairly present in all material
         respects the financial condition, results of operations and cash flows
         of the registrant as of, and for, the periods presented in this report;

4.       The registrant's other certifying officer and I are responsible for
         establishing and maintaining disclosure controls and procedures (as
         defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal
         control over financial reporting (as defined in Exchange Act Rules
         13a-15(f) and 15d-15(f)) for the registrant and have:


         a)       Designed
 such disclosure controls and procedures, or caused
                  such disclosure controls and procedures to be designed under
                  our supervision, to ensure that material information relating
                  to the registrant, including its consolidated subsidiaries, is
                  made known to us by others within those entities, particularly
                  during the period in which this report is being prepared;


         b)       Designed such internal control over financial reporting, or
                  caused such internal control over financial reporting to be
                  designed under our supervision, to provide reasonable
                  assurance regarding the reliability of financial reporting and
                  the preparation of financial statements for external purposes
                  in accordance with generally accepted accounting principles;


         c)       Evaluated the effectiveness of the registrant's disclosure
                  controls and procedures and presented in this report our
                  conclusions about the effectiveness of the disclosure controls
                  and procedures, as of the end of the period covered by this
                  report based on such evaluation; and


         d)       Disclosed in this report any change in the registrant's
                  internal control over financial reporting that occurred during
                  the registrant's most recent fiscal quarter (the registrant's
                  fourth fiscal quarter in the case of an annual report) that
                  has materially affected, or is reasonably likely to materially
                  affect, the registrant's internal control over financial
                  reporting; and

5.       The registrant's other certifying officer and I have disclosed, based
         on our most recent evaluation of internal control over financial
         reporting, to the registrant's auditors and the audit committee of
         registrant's board of directors (or persons performing the equivalent
         functions):


         a)       All significant deficiencies and material weaknesses in the
                  design or operation of internal control over financial
                  reporting which are reasonably likely to adversely affect the
                  registrant's ability to record, process, summarize and report
                  financial information; and


         b)       Any fraud, whether or not material, that involves management
                  or other employees who have a significant role in the
                  registrant's internal control over financial reporting.


Date:  March 15, 2005
                               /s/ Terence E. Hall
                               -------------------------------------------------
                               Terence E. Hall
                               Chairman of the Board and Chief Executive Officer
                               Superior Energy Services, Inc.



<PAGE>


                                                                    EXHIBIT 31.2

                            CERTIFICATION PURSUANT TO
    RULES 13A-14(a) AND 15D-14(a) UNDER THE SECURITIES EXCHANGE ACT OF 1934,
                                   AS AMENDED

         I, Robert S. Taylor, Executive Vice President and Chief Financial
Officer of Superior Energy Services, Inc., certify that:

1.       I have reviewed this annual report on Form 10-K of Superior Energy
         Services, Inc.;

2.       Based on my knowledge, this report does not contain any untrue
         statement of a material fact or omit to state a material fact necessary
         to make the statements made, in light of the circumstances under which
         such statements were made, not misleading with respect to the period
         covered by this report;

3.       Based on my knowledge, the financial statements, and other financial
         information included in this report, fairly present in all material
         respects the financial condition, results of operations and cash flows
         of the registrant as of, and for, the periods presented in this report;

4.       The registrant's other certifying officer and I are responsible for
         establishing and maintaining disclosure controls and procedures (as
         defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal
         control over financial reporting (as defined in Exchange Act Rules
         13a-15(f) and 15d-15(f)) for the registrant and have:



         a)       Designed such disclosure controls and procedures, or caused
                  such disclosure controls and procedures to be designed under
                  our supervision, to ensure that material information relating
                  to the registrant, including its consolidated subsidiaries, is
                  made known to us by others within those entities, particularly
                  during the period in which this report is being prepared;


         b)       Designed such internal control over financial reporting, or
                  caused such internal control over financial reporting to be
                  designed under our supervision, to provide reasonable
                  assurance regarding the reliability of financial reporting and
                  the preparation of financial statements for external purposes
                  in accordance with generally accepted accounting principles;


         c)       Evaluated the effectiveness of the registrant's disclosure
                  controls and procedures and presented in this report our
                  conclusions about the effectiveness of the disclosure controls
                  and procedures, as of the end of the period covered by this
                  report based on such evaluation; and


         d)       Disclosed in this report any change in the registrant's
                  internal control over financial reporting that occurred during
                  the registrant's most recent fiscal quarter (the registrant's
                  fourth fiscal quarter in the case of an annual report) that
                  has materially affected, or is reasonably likely to materially
                  affect, the registrant's internal control over financial
                  reporting; and

5.       The registrant's other certifying officer and I have disclosed, based
         on our most recent evaluation of internal control over financial
         reporting, to the registrant's auditors and the audit committee of
         registrant's board of directors (or persons performing the equivalent
         functions):


         a)       All significant deficiencies and material weaknesses in the
                  design or operation of internal control over financial
                  reporting which are reasonably likely to adversely affect the
                  registrant's ability to record, process, summarize and report
                  financial information; and


         b)       Any fraud, whether or not material, that involves management
                  or other employees who have a significant role in the
                  registrant's internal control over financial reporting.


Date:  March 15, 2005
                            /s/ Robert S. Taylor
                            ----------------------------------------------------
                            Robert S. Taylor
                            Executive Vice President and Chief Financial Officer
                            Superior Energy Services, Inc.


<PAGE>


                                                                    EXHIBIT 32.1


                            CERTIFICATION PURSUANT TO
                    SECTION 1350 OF TITLE 18 OF THE U.S. CODE

I, Terence E. Hall, Chairman of the Board and Chief Executive Officer of
Superior Energy Services, Inc. (the "Company"), certify, pursuant to Section
1350 of Title 18 of the U.S. Code, adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002 ("Section 906"), that:

1.        the annual report on Form 10-K of the Company for the year ended
          December 31, 2004 (the "Report"), as filed with the Securities and
          Exchange Commission on the date hereof, fully complies with the
          requirements of Section 13(a) or 15(d) of the Securities Exchange Act
          of 1934; and

2.       the information contained in the Report fairly presents, in all
         material respects, the financial condition and results of operations of
         the Company.

This certificate is being furnished solely for purposes of Section 906 and is
not being filed as part of the Report or as a separate disclosure document.

Date:  March 15, 2005
                               /s/ Terence E. Hall
                               -------------------------------------------------
                               Terence E. Hall
                               Chairman of the Board and Chief Executive Officer
                               Superior Energy Services, Inc.


A signed original of this written statement required by Section 906 has been
provided to the Company and will be retained by the Company and furnished to the
Securities and Exchange
 Commission or its staff upon request.



<PAGE>


                                                                    EXHIBIT 32.2


                            CERTIFICATION PURSUANT TO
                    SECTION 1350 OF TITLE 18 OF THE U.S. CODE

I, Robert S. Taylor, Executive Vice President and Chief Financial Officer of
Superior Energy Services, Inc. (the "Company"), certify, pursuant to Section
1350 of Title 18 of the U.S. Code, adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002 ("Section 906"), that:

1.        the annual report on Form 10-K of the Company for the year ended
          December 31, 2004 (the "Report"), as filed with the Securities and
          Exchange Commission on the date hereof, fully complies with the
          requirements of Section 13(a) or 15(d) of the Securities Exchange Act
          of 1934; and

2.       the information contained in the Report fairly presents, in all
         material respects, the financial condition and results of operations of
         the Company.

This certificate is being furnished solely for purposes of Section 906 and is
not being filed as part of the Report or as a separate disclosure document.

Date:  March 15, 2005
                            /s/ Robert S. Taylor
                            ----------------------------------------------------
                            Robert S. Taylor
                            Executive Vice President and Chief Financial Officer
                            Superior Energy Services, Inc.


A signed original of this written statement required by Section 906 has been
provided to the Company and will be retained by the Company and furnished to the
Securities
 and Exchange Commission or its staff upon request.