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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, 2006
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 incorporation or organization)   (I.R.S. Employer 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 if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of 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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.
Large accelerated filer þ       Accelerated filer o       Non-accelerated o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
The aggregate market value of the voting stock held by non-affiliates of the registrant at June 30, 2006 based on the closing price on the New York Stock Exchange on that date was $2,726,758,000.
The number of shares of the registrant’s common stock outstanding on February 16, 2007 was 80,636,962.
DOCUMENTS INCORPORATED BY REFERENCE
Certain information called for by Items 10, 11, 12, 13 and 14 of Part III is incorporated by reference from the 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, 2006
TABLE OF CONTENTS
             
        Page  
           
 
           
  Business     1  
  Risk Factors     10  
  Unresolved Staff Comments     16  
  Properties     16  
  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     20  
  Management’s Discussion and Analysis of Financial Condition and Results of Operations     21  
  Quantitative and Qualitative Disclosures about Market Risk     33  
  Financial Statements and Supplementary Data     35  
  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     80  
  Controls and Procedures     80  
  Other Information     80  
 
           
           
 
           
  Directors, Executive Officers and Corporate Governance     81  
  Executive Compensation     81  
  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     81  
  Certain Relationships and Related Transactions, and Director Independence     81  
  Principal Accountant Fees and Services     81  
 
           
           
 
           
  Exhibits and Financial Statement Schedules     82  
 Subsidiaries
 Consent of KPMG LLP
 Consent of DeGolyer and MacNaughton
 Officer's Certification Pursuant to Rule 13a-14(a)
 Officer's Certification Pursuant to Rule 13a-14(a)
 Officer's Certification Pursuant to Section 1350
 Officer's Certification Pursuant to Section 1350

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FORWARD-LOOKING STATEMENTS
We have included or incorporated by reference in this Annual Report on Form 10-K, and from time to time our management may make, statements that may constitute “forward-looking statements” within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements are not historical facts but instead represent only our current belief regarding future events, many of which, by their nature, are inherently uncertain and outside our control. The forward-looking statements contained in this Annual Report are based on information as of the date of this Annual Report. Many of these forward looking statements relate to future industry trends, actions, future performance or results of current and anticipated initiatives and the outcome of contingencies and other uncertainties that may have a significant impact on our business, future operating results and liquidity. We try, whenever possible, to identify these statements by using words such as “anticipate,” “believe,” “should,” “estimate,” “expect,” “plan,” “project” and similar expressions. We caution you that these statements are only predictions and are not guarantees of future performance. These forward-looking statements and our actual results, developments and business are subject to certain risks and uncertainties that could cause actual results and events to differ materially from those anticipated by these statements. By identifying these statements for you in this manner, we are alerting you to the possibility that our actual results may differ, possibly materially, from the anticipated results indicated in these forward-looking statements. Important factors that could cause actual results to differ from those in the forward-looking statements include, among others, those discussed below and under “Risk Factors” in Part I, Item 1A and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7.
PART I
Item 1. Business
General
We are a leading, highly diversified provider of specialized oilfield services and equipment. We focus on serving the drilling-related needs of oil and gas companies primarily through our rental tools segment, and the production-related needs of oil and gas companies through our well intervention, rental tools and marine segments. We believe that we are one of the few companies capable of providing the services, tools and liftboats necessary to maintain, enhance and extend the life of offshore producing wells, as well as plug and abandonment services at the end of their life cycle. We also own and operate mature oil and gas properties in the Gulf of Mexico. We believe that our ability to provide our customers with multiple services and to coordinate and integrate their delivery allows us to maximize efficiency, reduce lead-time and provide cost-effective solutions for our customers. We have expanded geographically so that we now have a significant presence in both select domestic land and international markets.
Operations
Our operations are organized into the following four business segments:
Well Intervention Services. We provide well intervention services that stimulate oil and gas production. Our well intervention services include coiled tubing, electric line, pumping and stimulation, gas lift, well control, snubbing, recompletion, engineering and well evaluation services, platform and field management, offshore oil and gas cleaning, decommissioning, plug and abandonment and mechanical wireline. We believe we are the leading provider of mechanical wireline services in the Gulf of Mexico with approximately 210 offshore wireline units, 90 land wireline units and 10 dedicated liftboats configured specifically for wireline services. We also believe we are a leading provider of rigless plug and abandonment services in the Gulf of Mexico. We recently completed construction of an 880-ton derrick barge which was deployed off the coast of Malaysia under a charter that is scheduled to run through October 2007. We also manufacture and sell specialized drilling rig instrumentation equipment.
In December 2006, we significantly expanded the domestic land presence of our well intervention segment when we acquired Warrior Energy Services Corporation (“Warrior”), a provider of production-related services. Warrior has 82 electric line units, 15 rig-assist snubbing units and six coiled tubing units and provides services onshore in

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Alabama, Arkansas, Colorado, Kansas, Louisiana, Mississippi, Montana, New Mexico, North Dakota, Oklahoma, Texas, Utah and Wyoming, and offshore in the Gulf of Mexico.
Rental Tools. We are a leading provider of rental tools. We manufacture, sell and rent specialized equipment for use with offshore and onshore oil and gas well drilling, completion, production and workover activities. Through internal growth and acquisitions, we have increased the size and breadth of our rental tool inventory and geographic scope of operations so that we now conduct operations offshore in the Gulf of Mexico, onshore in the United States and in select international market areas. We currently have locations in all of the major staging points in Louisiana and Texas for offshore oil and gas activities in the Gulf of Mexico and in North Louisiana, Arkansas, Oklahoma and Wyoming. Our rental tools segment also conducts operations in Venezuela, Trinidad, Mexico, Colombia, Eastern Canada, the United Kingdom, Continental Europe, the Middle East, West Africa and the Asia Pacific region. Our rental tools include pressure control equipment, specialty tubular goods including drill pipe and landing strings, connecting iron, handling tools, bolting equipment, stabilizers, drill collars and on-site accommodations.
Marine Services. We own and operate a fleet of liftboats that we believe is highly complementary to our well intervention services. A liftboat is a self-propelled, self-elevating work platform with legs, cranes and living accommodations. Our fleet consists of 37 liftboats, including 10 liftboats configured specifically for wireline services (included in our well intervention segment) and 27 in our rental fleet with leg-lengths ranging from 145 feet to 250 feet. Our liftboat fleet has leg-lengths and deck spaces that are suited to deliver our production-related bundled services and support customers in their construction, maintenance and other production-enhancement projects. All of our liftboats are currently located in the Gulf of Mexico, but we may reposition some of our larger liftboats to international market areas if opportunities arise.
Oil and Gas Operations. Through our subsidiary, SPN Resources, LLC (“SPN Resources”), we acquire mature oil and gas properties in the Gulf of Mexico to provide our customers a cost-effective alternative to the plugging, abandoning and decommissioning process. Owning oil and gas properties provides additional opportunities for our well intervention, decommissioning and platform management services, particularly during periods when demand from our traditional customers is weak due to cyclical or seasonal factors. Once properties are acquired, we utilize our production-related assets and services to maintain, enhance and extend existing production of these properties. At the end of a property’s economic life, we plug and abandon the wells and decommission and abandon the facilities. As of December 31, 2006, we had interests in 31 offshore blocks containing 65 structures and approximately 156 producing wells. As of December 31, 2006, we had reserves of approximately 13.9 million barrels of oil equivalent (mmboe) with a PV-10 of $230.6 million and approximately 83% of our reserves were classified as proved developed.
For additional industry segment financial information, see note 15 to our consolidated financial statements included in Item 8 of this Form 10-K.
Customers
Our customers have primarily been the major and independent oil and gas companies. Sales to Shell accounted for approximately 12% and 10% of our total revenue in 2006 and 2005, respectively. In 2004, no customer accounted for more than 10% of revenue. We do not believe that the loss of any one customer would have a material adverse effect on our revenues. However, our inability to continue to perform services for a number of our large existing customers, if not offset by sales to new or other existing customers could have a material adverse effect on our business and operations.
Competition
We operate in highly competitive areas of the oilfield services industry. The products and services of each of our principal operating segments are sold in highly competitive markets, and our revenues and earnings can be affected by the following factors:
    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;

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    changes in the number of liftboats operating in the Gulf of Mexico;
 
    the ability of oil and gas producers to generate capital;
 
    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 provided by our well intervention segment. The rental tools divisions of these companies, as well as several smaller companies that are single source providers of rental tools, are our competitors in the rental tools market. In the marine services segment, we compete with other companies that provide liftboat services in the Gulf of Mexico. We also compete with other companies for the acquisition of mature oil and gas properties in the Gulf of Mexico. We believe that the principal competitive factors in the market areas that we serve are price, product and service quality, safety record, equipment availability and technical proficiency.
Our operations may be adversely affected if our current competitors or new market entrants introduce new products or services with better features, performance, prices or other characteristics than our products and services, or if they would offer to pay more for mature oil and gas properties. Further, if our competitors construct additional liftboats for the Gulf of Mexico market area, it could affect vessel utilization and resulting day rates. Competitive pressures or other factors also may result in significant price competition that could reduce our operating cash flow and earnings. In addition, competition among oilfield service and equipment providers is affected by each provider’s reputation for safety and quality. Although we believe that our reputation for safety and quality service is good, we cannot assure that we will be able to maintain our competitive position.
Health, Safety and Environmental Assurance
We have established health, safety and environmental performance as a corporate priority. Our goal is to be an industry leader in this area by focusing on the belief that all safety and environmental incidents are preventable and an injury-free workplace is achievable by emphasizing correct behavior. We have a company-wide effort to enhance our behavioral safety process and training program and make safety a constant focus of awareness through open communication with all of our offshore and yard employees. In addition, we investigate all incidents with a priority of identifying and implementing the corrective measures necessary to reduce the chance of reoccurrence.
Potential Liabilities and Insurance
Our operations involve a high degree of operational risk, particularly of personal injury, damage or loss of equipment and environmental accidents. Failure or loss of our equipment could result in property damages, personal injury, environmental pollution and other damage for which we could be liable. Litigation arising from the sinking of a liftboat or a catastrophic occurrence, such as a fire, explosion or well blowout, at one of our offshore production facilities or a location where our equipment and services are used may result in large claims for damages in the future. We maintain insurance against risks that we believe is consistent in types and amounts with industry standards and is required by our customers. Changes in the insurance industry in the past few years have led to higher insurance costs and deductibles, as well as lower coverage limits causing us to rely on self insurance against many risks associated with our business. The availability of insurance covering risks we and our competitors typically insure against may continue to decrease forcing us to self insure against more business risks, including the risks associated with hurricanes, and the insurance that we are able to obtain may have higher deductibles, higher premiums, lower limits and more restrictive policy terms.
Government Regulation
Our business is significantly affected by the following:
    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.

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We cannot predict the level of enforcement of existing laws and regulations or how such laws and regulations may be interpreted by enforcement agencies or court rulings in the future. A decrease in the level of industry compliance with or enforcement of these laws and regulations in the future may adversely affect the demand for our services. We also cannot predict whether additional laws and regulations will be adopted, or the effect such changes may have on us, our businesses or our financial condition. The demand for our services from the oil and gas industry would be affected by changes in applicable laws and regulations. The adoption of new laws and regulations curtailing drilling for oil and gas in our operating areas for economic, environmental or other policy reasons could also adversely affect our operations by limiting demand for our services.
Regulation of Oil and Gas Production
The oil and gas industry is subject to various types of regulation at federal and state levels. This regulation includes requiring permits to drill wells, maintaining bonding requirements to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, stringent engineering and construction standards, and the plugging and abandoning of wells and removal of production facilities. The oil and gas industry is also subject to various federal and state conservation laws and regulations. These include regulations establishing maximum rates of production from oil and natural gas wells, generally prohibiting the venting or flaring of natural gas and imposing certain requirements regarding the ratability of production.
Virtually all of our oil and gas operations are located on federal oil and gas leases, which are administered by the U.S. Department of Interior, Minerals Management Service, or MMS, pursuant to the Outer Continental Shelf Lands Act, or OCSLA. These leases contain standardized terms that require compliance with detailed MMS regulations and orders that are subject to interpretation and change by MMS. Under some circumstances, MMS may require operations on federal leases to be suspended or terminated.
To cover the various obligations of lessees on the Outer Continental Shelf, MMS generally requires that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be met. The cost of these bonds or assurances can be substantial, and there is no assurance that they can be obtained in all cases. We currently have bonded our offshore leases, as required by MMS, consisting of a $3.0 million Area-Wide Bond plus a $300,000 Pipeline Right-of-Way Bond. Currently, we are exempt from supplemental bonding.
MMS also administers the collection of royalties under the terms of the OCSLA and the oil and gas leases issued under the act. The amount of royalties due is based upon the terms of the oil and gas leases as well as the regulations promulgated by MMS. These regulations are amended from time to time, and the amendments can affect the amount of royalties that we are obligated to pay to MMS. However, we do not believe that these regulations or any future amendments will affect us in a way that materially differs from the way it affects other oil and gas producers.
These regulations impact our customers’ needs for our services, as well as limit the amounts of oil and natural gas we can produce from our wells. Because these statutes, rules and regulations undergo constant review and often are amended, expanded and reinterpreted, we are unable to predict the future cost or impact of regulatory compliance. The regulatory burden on the oil and gas industry increases its cost of doing business and, consequently, affects our profitability.
Natural Gas Marketing, Gathering and Transportation
Historically, the transportation and sales of natural gas in interstate commerce have been regulated pursuant to the various laws administered by the Federal Energy Regulatory Commission, or FERC. Currently, the price for all “first sales” of natural gas is not regulated by FERC. Accordingly, all of our natural gas sales may be made at market prices, subject to applicable contract provisions. Sales of natural gas are affected by the availability, terms and cost of pipeline transportation. FERC has also implemented regulations intended to make natural gas transportation more accessible to gas buyers and sellers on an open-access, non-discriminatory basis.
Certain of our pipeline systems are regulated for safety compliance by the U.S. Department of Transportation, or DOT. Pursuant to the Pipeline Safety Improvement Act of 2002, DOT has implemented regulations intended to increase pipeline operating safety. Among other provisions, the regulations require that pipeline operators

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implement a pipeline integrity management program that must at a minimum include an inspection of gas transmission pipeline facilities within the next ten years, and at least every seven years thereafter.
We cannot predict what new or different regulations FERC, DOT and other regulatory agencies may adopt, or what effect subsequent regulations may have on our activities. Similarly, it is impossible to predict what proposals, if any, that affect the oil and natural gas industry might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on us. Also, despite the recent trend toward federal deregulation of the natural gas industry, we cannot predict whether or to what extent that trend will continue, or what the ultimate effect will be on our sales of gas.
Federal Regulation of Petroleum
Our sales of oil and gas are not regulated and are at market prices. The price received from the sale of these products is affected by the cost of transporting the products to market. Much of that transportation is through interstate common carrier pipelines. FERC has implemented regulations approving interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may tend to increase the cost of transporting oil and natural gas by interstate pipeline, although the annual adjustments may result in decreased rates in a given year.
Environmental Regulations
General. Our operations are subject to extensive federal, state and local laws and regulations relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. Permits are required for the conduct of our business and operation of our various marine vessels and offshore production facilities. These permits can be revoked, modified or renewed by issuing authorities. Governmental authorities enforce compliance with their regulations through administrative or civil penalties, corrective action orders, injunctions or criminal prosecution. Government regulations can increase the cost of planning, designing, installing and operating our oil and gas properties. Although we believe that compliance with environmental regulations will not have a material adverse effect on us, risks of substantial costs and liabilities related to environmental compliance issues are part of oil and gas production operations. No assurance can be given that significant costs and liabilities will not be incurred. Also, it is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from oil and gas production could result in substantial costs and liabilities to us.
Federal laws and regulations applicable to our operations include those controlling the discharge of materials into the environment, requiring removal and cleanup of materials that may harm the environment, requiring consistency with applicable coastal zone management plans, or otherwise relating to the protection of the environment.
Our insurance policies provide liability coverage for sudden and accidental occurrences of pollution or clean-up and containment in amounts that we believe are comparable to policy limits carried by others in our industry.
Outer Continental Shelf Lands Act. OCSLA and regulations promulgated pursuant thereto impose a variety of regulations relating to safety and environmental protection applicable to lessees, permits and other parties operating on the Outer Continental Shelf. Specific design and operational standards may apply to Outer Continental Shelf vessels, rigs, platforms, vehicles and structures. Violations of lease conditions or regulations issued pursuant to OCSLA can result in substantial civil and criminal penalties as well as potential court injunctions curtailing operations and the cancellation of leases. Enforcement liabilities under OCSLA can result from either governmental or citizen prosecution. We believe that we substantially comply with OCSLA and its regulations.
Solid and Hazardous Waste. We currently lease numerous properties that have been used in connection with the production of oil and gas for many years. Although we believe we utilized operating and disposal practices that were standard in the industry at the time, it is possible that hydrocarbons or other solid wastes may have been disposed of or released on or under the properties currently leased by us. Federal and state laws applicable to oil and gas wastes and properties continue to be stricter over time. Under these increasingly stringent requirements, we could be required to remove or remediate previously disposed wastes (including wastes disposed or released by prior

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owners and operators) or clean up property contamination (including groundwater contamination by prior owners or operators) or to perform plugging operations to prevent future contamination. We generate some hazardous wastes that are already subject to the Federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes. The Environmental Protection Agency, or the EPA, has limited the disposal options for certain hazardous wastes. It is possible that certain wastes currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes under RCRA or other applicable statutes. We could, therefore, be subject to more rigorous and costly disposal requirements in the future than we encounter today.
Superfund. The Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain persons with respect to the release of hazardous substances into the environment. These persons include the owner and operator of a site and any party that disposed of or arranged for the disposal of hazardous substances found at a site. CERCLA also authorizes the EPA, and in some cases, private parties, to undertake actions to clean up such hazardous substances, or to recover the costs of such actions from the responsible parties. In the course of business, we have generated and will continue to generate wastes that may fall within 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 resulting from job related injuries, with generally no limitations on our potential liability.
Employees
As of January 31, 2007, we had approximately 4,300 employees. None of our employees is represented by a union or covered by a collective bargaining agreement. We believe that our relationship with our employees is good.
Facilities
Our corporate headquarters are located on a 17-acre tract in Harvey, Louisiana, which we also use to support our well intervention, marine and rental operations. Our other principal operating facility is located on a 32-acre tract in

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Broussard, Louisiana, which we use to support our rental tools and well intervention group operations in the Gulf of Mexico. We support the operations conducted by our liftboats from a 3.5-acre maintenance and office facility in New Iberia, Louisiana. We also own certain facilities and lease other office, service and assembly facilities under various operating leases, including a 7-acre office and training facility located in Houston, Texas. We have a total of approximately 120 owned or leased operating facilities located in Louisiana, Texas, Alabama, Arkansas, Mississippi, Oklahoma, Colorado, New Mexico, Utah, Wyoming, Venezuela, Australia, Trinidad, Mexico, Colombia, the United Kingdom, the Netherlands, Eastern Canada, United Arab Emirates, and Nigeria to support our operations. We believe that all of our leases are at competitive or market rates and do not anticipate any difficulty in leasing suitable additional space as may be needed or extending terms when our current leases expire.
Oil and Natural Gas Reserves
The following table presents our estimated net proved oil and natural gas reserves at December 31, 2006, 2005 and 2004 and estimated future net revenues and cash flows attributable thereto. Our proved reserves for 2006, 2005 and 2004 were estimated by DeGolyer and MacNaughton, independent petroleum engineers. The oil and natural reserve information contained herein do not include the reserves owned by our equity-method investee, Coldren Resources L.P.
                         
    As of December 31,
    2006   2005   2004
Total estimated net proved reserves:
                       
Oil (Mbbls)
    7,921       9,103       9,120  
Natural gas (Mmcf)
    35,641       23,688       29,380  
Total (Mboe) (1)
    13,861       13,051       14,017  
Net proved developed reserves (4):
                       
Oil (Mbbls)
    6,709       7,554       7,731  
Natural gas (Mmcf)
    28,982       21,703       25,542  
Total (Mboe) (1)
    11,539       11,171       11,988  
Estimated future net revenues before income taxes (in thousands) (2)
  $ 254,600     $ 441,550     $ 285,437  
Standardized measure of discounted future net cash flows (in thousands) (3)
  $ 178,741     $ 205,105     $ 136,507  
 
(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 December 31, 2006 amount was estimated by DeGolyer and MacNaughton using a period-end crude New York Mercantile Exchange (NYMEX) price of $61.05 per bbl for oil and a NYMEX gas price of $5.64 per million British Thermal units for natural gas, and price differentials provided by us. The December 31, 2005 amount was also estimated by DeGolyer and MacNaughton using a period-end crude NYMEX price of $61.04 per bbl for oil and a NYMEX gas price of $9.44 per million British Thermal units for natural gas, and price differentials provided by us. The December 31, 2004 amount was also estimated by DeGolyer and MacNaughton using a period-end crude NYMEX price of $43.46 per bbl for oil and a Henry Hub gas price of $6.19 per million British Thermal units for natural gas, and price differentials provided by us. Net revenues as they appear in the table are defined as gross revenue, less production taxes, operating expenses and capital costs.
 
(3)   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%.
 
(4)   Net proved developed non-producing reserves at December 31, 2006 were 3,214 mbbls (41% of total net proved oil reserves) and 15,655 mmcf (44% of total net proved gas reserves). Net proved undeveloped reserves as of December 31, 2006 were 1,212 mbbls (15% of total net proved oil reserves) and 6,659 mmcf (19% of total net proved gas reserves).

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Since January 1, 2005 no crude oil or natural gas reserve information has been filed with, or included in any report to any federal authority or agency other than the SEC and the Energy Information Administration (“EIA”). The Company files Form 23, including reserve and other information with the EIA.
Our reserve information is prepared in accordance with guidelines established by the Securities and Exchange Commission, including using prices and costs determined on the date of the actual estimate, without considering hedge contracts in place at the end of the period, and a 10% discount rate to determine the present value of future net cash flow. There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control such as commodity pricing. Therefore, the foregoing reserve information represents only estimates, and is not intended to represent the current market value of our estimated oil and natural gas reserves. We believe that the following factors should be taken into account in reviewing our reserve information: (1) future costs and selling prices will differ from those required to be used in these calculations; (2) actual rates of production achieved in future years may vary significantly from the production rates assumed in the calculations; (3) selection of a 10% discount rate is arbitrary and may not be reasonable as a measure of the relative risk inherent in realizing future net oil and gas revenues; and (4) future net revenues may be subject to different rates of income taxation.
Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that can not be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers often vary. In addition, results of production subsequent to the date of an estimate may justify revising the original estimate. Accordingly, reserve estimates at any point in time are generally different from the quantities of oil and gas that are ultimately produced. The meaningfulness of these estimates depends primarily on the accuracy of the assumptions upon which they were based. Except to the extent we acquire additional properties containing proved reserves, our proved reserves should decline as reserves are produced.
Productive Wells Summary
The following table presents our ownership at December 31, 2006, of productive oil and natural gas wells. Productive wells consist of producing wells and wells capable of production. Twenty gross oil wells and seven gross natural gas wells have dual completions. In the table, “gross” refers to the total wells in which we own an interest and “net” refers to the sum of fractional interests owned in gross wells.
                 
    Total
    Productive Wells
    Gross   Net
Oil
    295.00       286.60  
Natural gas
    71.00       57.31  
 
               
 
               
Total
    366.00       343.91  
 
               
As of December 31, 2006, only approximately 156 of our gross wells were actually producing. Due to the maturity of our properties, a number of our productive wells are not able to produce on a regular basis or without incurring significant additional costs. Accordingly, they may never actually produce.
Acreage
The following table sets forth information as of December 31, 2006 relating to acreage held by us. Developed acreage is assigned to productive wells.

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    Gross   Net
    Acreage   Acreage
Developed
    130,299       102,351  
Undeveloped
           
 
               
 
               
Total
    130,299       102,351  
 
               
Drilling Activity
The following table shows our drilling activity for the years ended December 31, 2006, 2005 and 2004. We did not drill any exploratory wells during the periods covered by the table. In the table, “gross” refers to the total wells in which we have a working interest and “net” refers to the gross wells multiplied by our working interest in these wells. Well activity refers to the number of wells completed during a fiscal year, regardless of when drilling first commenced. For this table, “completed” refers to the installation of permanent equipment for the production of oil and gas.
                                                 
    2006   2005   2004
    Gross   Net   Gross   Net   Gross   Net
Development Wells:
                                               
Productive
    7.00       1.40       1.00       0.50       3.00       0.06  
Non-productive
                                   
 
                                               
 
                                               
Total
    7.00       1.40       1.00       0.50       3.00       0.06  
 
                                               
These wells were proposed and drilled under the supervision of our exploitation partners.
Costs Incurred in Oil and Natural Gas Activities
The following table displays certain information regarding the costs incurred associated with finding, acquiring and developing our proved oil and natural gas reserves for the years ended December 31, 2006, 2005 and 2004 (in thousands).
                         
    Years Ended December 31,  
    2006     2005     2004  
Acquisition of properties — proved
  $ 45,948     $ 9,015     $ 81,356  
Development costs
    63,396       19,867       4,707  
 
                 
 
                       
Total costs incurred
  $ 109,344     $ 28,882     $ 86,063  
 
                 
Capitalized costs for oil and gas producing activities consist of the following (in thousands):
                         
    2006     2005     2004  
Proved properties
  $ 109,344     $ 28,882     $ 86,063  
Accumulated depreciation, depletion and amortization
    (26,308 )     (18,065 )     (7,156 )
 
                 
 
                       
Capitalized costs, net
  $ 83,036     $ 10,817     $ 78,907  
 
                 
Intellectual Property
We use several patented items in our operations that we believe are important, but not indispensable, to our operations. Although we anticipate seeking patent protection when possible, we rely to a greater extent on the technical expertise and know-how of our personnel to maintain our competitive position.

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Other Information
We have our principal executive offices at 1105 Peters Road, Harvey, Louisiana 70058. Our telephone number is (504) 362-4321. We also have a website at http://www.superiorenergy.com. Copies of the annual, quarterly and current reports we file with the SEC, and any amendments to those reports, are available on our website free of charge, soon after such reports are filed with or furnished to the SEC. The information posted on our website is not incorporated into this Annual Report on Form 10-K. Alternatively, you may access these reports at the SEC’s internet website: http://www.sec.gov/ .
We have adopted a Code of Business Ethics and Conduct, which applies to all of our directors, officers and employees. The Code of Business Ethics and Conduct is publicly available on our website at http://www.superiorenergy.com. Any waivers to the Code of Business Ethics and Conduct by directors or executive officers and any material amendment to the Code of Business Ethics and Conduct will be posted promptly on our website and/or disclosed in a current report on Form 8-K.
Item 1A. Risk Factors
You should carefully consider the following factors in addition to the other information contained in this Annual Report. The risks described below are the material risks that we have identified. There are many factors that affect our business and the results of our operations, many of which are beyond our control. In addition, they may not be the only material risks that we face. Additional risks and uncertainities not currently known to us or that we currently view as immaterial may also impair our business operations. If any of these risks develop into actual events, it could materially and adversely affect our business, financial condition, results of operations and cash flows. If that occurred, the trading price of our common stock could decline and you could lose part or all of your investment.
We are subject to the cyclical nature of the oil and gas industry.
Demand for the majority of our oilfield services is substantially dependent on the level of expenditures by the oil and gas industry. This level of activity has traditionally been volatile as a result of sensitivities to oil and gas prices and generally dependent on the industry’s view of future oil and gas prices. The purchases of the products and services we provide are, to a substantial extent, deferrable in the event oil and gas companies reduce expenditures. Therefore, the willingness of our customers to make expenditures is critical to our operations. Oil and gas prices have historically been volatile and are affected by many factors, including:
    the level of worldwide oil and gas exploration and production;
 
    the cost of exploring for, producing and delivering oil and gas;
 
    demand for energy, which is affected by worldwide economic activity and population growth;
 
    the ability of the Organization of Petroleum Exporting Countries, or OPEC, to set and maintain production levels for oil;
 
    the discovery rate of new oil and gas reserves;
 
    political and economic uncertainty, socio-political unrest and regional instability or hostilities; and
 
    technological advances affecting energy exploration, production and consumption.
Although activity levels in production and development sectors of the oil and gas industry are less immediately affected by changing prices and as a result, less volatile than the exploration sector, producers generally react to declining oil and gas prices by reducing expenditures. This has in the past adversely affected and may in the future, adversely affect our business. We are unable to predict future oil and gas prices or the level of oil and gas industry activity. A prolonged low level of activity in the oil and gas industry will adversely affect the demand for our products and services and our financial condition, results of operations and cash flows.
Our industry is highly competitive.
We compete in highly competitive areas of the oilfield services industry. The products and services of each of our principal industry segments are sold in highly competitive markets, and our revenues and earnings may be affected by the following factors:
    changes in competitive prices;
 
    fluctuations in the level of activity in major markets;
 
    an increased number of liftboats in the Gulf of Mexico;
 
    general economic conditions; and

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    governmental regulation.
We compete with the oil and gas industry’s largest integrated and independent oilfield service providers. We believe that the principal competitive factors in the market areas that we serve are price, product and service quality, availability and technical proficiency.
Our operations may be adversely affected if our current competitors or new market entrants introduce new products or services with better features, performance, prices or other characteristics than our products and services. Further, additional liftboat capacity in the Gulf of Mexico would increase competition for that service. Competitive pressures or other factors also may result in significant price competition that could have a material adverse effect on our results of operations and financial condition. Finally, competition among oilfield service and equipment providers is also affected by each provider’s reputation for safety and quality. Although we believe that our reputation for safety and quality service is good, we cannot guarantee that we will be able to maintain our competitive position.
Estimates of our oil and gas reserves and potential liabilities relating to our oil and gas properties may be incorrect.
We acquire mature oil and gas properties in the Gulf of Mexico on an “as is” basis and assume all plugging, abandonment, restoration and environmental liability with limited remedies for breaches of representations and warranties. Acquisitions of these properties require an assessment of a number of factors beyond our control, including estimates of recoverable reserves, future oil and gas prices, operating costs and potential environmental and plugging and abandonment liabilities. These assessments are complex and inherently imprecise, and, with respect to estimates of oil and gas reserves, require significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. In addition, since these properties are typically mature, our facilities and operations may be more susceptible to hurricane damage, equipment failure or mechanical problems. In connection with these assessments, we perform due diligence reviews that we believe are generally consistent with industry practices. However, our reviews may not reveal all existing or potential problems. In addition, our reviews may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We may not always discover structural, subsurface, environmental or other problems that may exist or arise.
Actual future production, cash flows, development expenditures, operating and abandonment expenses and quantities of recoverable oil and gas reserves may vary substantially from those estimated by us and any significant variance in these assumptions could materially affect the estimated quantity and value of our proved reserves. Therefore, the risk is that we may overestimate the value of economically recoverable reserves and/or underestimate the cost of plugging wells and abandoning production facilities. If costs of abandonment are materially greater or actual reserves are materially lower than our estimates, they could have an adverse effect on earnings.
A significant portion of our revenue is derived from our non-United States operations, which exposes us to additional political, economic and other uncertainties.
Our non-United States revenues account for approximately 15%, 14% and 16% of our total revenues in 2006, 2005, and 2004, respectively. Our international operations are subject to a number of risks inherent in any business operating in foreign countries including, but not limited to:
    political, social and economic instability;
 
    potential seizure or nationalization of assets;
 
    increased operating costs;
 
    social unrest, acts of terrorism, war or other armed conflict;
 
    modification or renegotiating of contracts;
 
    import-export quotas;
 
    confiscatory taxation or other adverse tax policies;
 
    currency fluctuations;
 
    restrictions on the repatriation of funds; and
 
    other forms of government regulation which are beyond our control.

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Additionally, our competitiveness in international market areas may be adversely affected by regulations, including, but not limited to, regulations requiring:
    the awarding of contracts to local contractors;
 
    the employment of local citizens; and
 
    the establishment of foreign subsidiaries with significant ownership positions reserved by the foreign government for local citizens.
The occurrence of any of the risks described above could adversely affect our results of operations and cash flows.
We are susceptible to adverse weather conditions in the Gulf of Mexico.
Certain areas in and near the Gulf of Mexico experience hurricanes and other extreme weather conditions on a relatively frequent basis. Substantially all of our facilities and assets offshore and along the Gulf of Mexico, including the structures and pipelines on our offshore oil and gas properties, are susceptible to damage and/or total loss by these storms. Damage caused by high winds and turbulent seas could potentially cause us to curtail both service and production operations for significant periods of time until damage can be assessed and repaired. Moreover, even if we do not experience direct damage from any of these storms, we may experience disruptions in our operations because customers may curtail their development activities due to damage to their platforms, pipelines and other related facilities.
Due to the losses as a consequence of the hurricanes that occurred in the Gulf of Mexico in 2005 and 2004, we have not been able to obtain insurance coverage comparable with that of prior years, thus putting us at a greater risk of loss due to severe weather conditions. Any significant uninsured losses could have a material adverse effect on our financial position, results of operations and cash flows.
We are vulnerable to the potential difficulties associated with rapid expansion.
We have grown rapidly over the last several years through internal growth and acquisitions of other companies. We believe that our future success depends on our ability to manage the rapid growth that we have experienced and the demands from increased responsibility on our management personnel. The following factors could present difficulties to us:
    lack of sufficient executive-level personnel;
 
    increased administrative burden; and
 
    increased logistical problems common to large, expansive operations.
If we do not manage these potential difficulties successfully, our operating results could be adversely affected.
We depend on key personnel.
Our success depends to a great degree on the abilities of our key management personnel, particularly our chief executive and operating officers and other high-ranking executives. The loss of the services of one or more of these key employees could adversely affect us.
We might be unable to employ a sufficient number of skilled workers.
The delivery of our products and services require personnel with specialized skills and experience. As a result, our ability to remain productive and profitable will depend upon our ability to employ and retain skilled workers. In addition, our ability to expand our operations depends in part on our ability to increase the size of our skilled labor force. The demand for skilled workers in our industry is high, and the supply is limited. In addition, although our employees are not covered by a collective bargaining agreement, the marine services industry has in the past been targeted by maritime labor unions in an effort to organize Gulf of Mexico employees. A significant increase in the wages paid by competing employers or the unionization of our Gulf of Mexico employees could result in a reduction

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of our skilled labor force, increases in the wage rates that we must pay or both. If either of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.
We depend on significant customers.
We derive a significant amount of our revenue from a small number of major and independent oil and gas companies. In 2006 and 2005, Shell accounted for approximately 12% and 10% of our total revenue, respectively. We did not have a single customer account for more than 10% of our total revenue in 2004. Our inability to continue to perform services for a number of our large existing customers, if not offset by sales to new or other existing customers, could have a material adverse effect on our business and operations.
The dangers inherent in our operations and the limits on insurance coverage could expose us to potentially significant liability costs and materially interfere with the performance of our operations.
Our operations are subject to numerous operating risks inherent in the oil and gas industry that could result in substantial losses. These risks include:
    fires;
 
    explosions, blowouts, and cratering;
 
    hurricanes and other extreme weather conditions;
 
    mechanical problems, including pipe failure;
 
    abnormally pressured formations; and
 
    environmental accidents, including oil spills, gas leaks or ruptures, uncontrollable flows of oil, gas, brine or well fluids, or other discharges of toxic gases or other pollutants.
Our liftboats are also subject to operating risks such as catastrophic marine disaster, adverse weather conditions, collisions and navigation errors.
The occurrence of these risks could result in substantial losses due to personal injury, loss of life, damage to or destruction of wells, production facilities or other property or equipment, or damages to the environment. In addition, certain of our employees who perform services on offshore platforms and marine vessels are covered by provisions of the Jones Act, the Death on the High Seas Act and general maritime law. These laws make the liability limits established by federal and state workers’ compensation laws inapplicable to these employees and instead permit them or their representatives to pursue actions against us for damages for job-related injuries. In such actions, there is generally no limitation on our potential liability.
Any litigation arising from a catastrophic occurrence involving our services, equipment or oil and gas production operations could result in large claims for damages. The frequency and severity of such incidents affect our operating costs, insurability and relationships with customers, employees and regulators. Any increase in the frequency or severity of such incidents, or the general level of compensation awards with respect to such incidents, could affect our ability to obtain projects from oil and gas companies or insurance. We maintain several types of insurance to cover liabilities arising from our services, including onshore and offshore non-marine operations, as well as marine vessel operations. These policies include primary and excess umbrella liability policies with limits of $50 million dollars per occurrence, including sudden and accidental pollution incidents. We also maintain property insurance on our physical assets, including marine vessels, and operating equipment. Successful claims for which we are not fully insured may adversely affect our working capital and profitability.
For our oil and gas operations, we maintain control of well, operators extra expense and pollution liability coverage, to include our liabilities under the federal Oil Pollution Act of 1990, or OPA. Limits maintained for well control incidents unrelated to windstorms range from $35 million to $50 million per occurrence. We have a limit of $75 million in the aggregate per policy year for named windstorm related events. The liability limit is $50 million per occurrence for non-well control events. We also maintain property insurance on our physical assets, including offshore production facilities and operating equipment. As a result of the losses caused by recent hurricanes in the Gulf of Mexico, we experienced substantial increases in our costs of insurance, as well as increased deductibles and self-insured retentions. Any significant uninsured losses could have a material adverse effect on our financial position, results of operations and cash flows.

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The cost of many of the types of insurance coverage maintained by us has increased significantly during recent years and resulted in the retention of additional risk by us, primarily through higher insurance deductibles. Very few insurance underwriters offer certain types of insurance coverage maintained by us, and there can be no assurance that any particular type of insurance coverage will continue to be available in the future, that we will not accept retention of additional risk through higher insurance deductibles or otherwise, or that we will be able to purchase our desired level of insurance coverage at commercially feasible rates. Further, due to the losses as a result of hurricanes that occurred in the Gulf of Mexico in 2005 and 2004, we were not be able to obtain insurance coverage comparable with that of prior years, thus putting us at a greater risk of loss due to severe weather conditions especially with our oil and gas properties. In addition, costs have significantly increased for windstorm, or hurricane, coverage which also impose higher deductibles and limit maximum aggregate recoveries. Any significant uninsured losses could have a material adverse effect on our financial position, results of operations and cash flows.
The occurrence of any of these risks could also subject us to clean-up obligations, regulatory investigation, penalties or suspension of operations. Further, our operations may be materially curtailed, delayed or canceled as a result of numerous factors, including:
    the presence of unanticipated pressure or irregularities in formations;
 
    equipment failures or accidents;
 
    adverse weather conditions;
 
    compliance with governmental requirements; and
 
    shortages or delays in obtaining drilling rigs or in the delivery of equipment and services.
Our oil and gas revenues are subject to commodity price risk.
We are subject to market risk exposure in the pricing applicable to our oil and gas production. Considering the historical and continued volatility and uncertainty of prices received for oil and gas production, we have and may continue to enter into hedging arrangements to reduce our exposure to decreases in the prices of natural gas and oil.
Hedging arrangements expose us to risk of significant financial loss in some circumstances including circumstances where:
    there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received;
 
    our production and/or sales of natural gas are less than expected;
 
    payments owed under derivative hedging contracts typically come due prior to receipt of the hedged 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.

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Factors beyond our control affect our ability to market oil and gas.
The availability of markets and the volatility of product prices are beyond our control and represent a significant risk. The marketability of our production depends upon the availability and capacity of gas gathering systems, pipelines and processing facilities. The unavailability or lack of capacity of these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Our ability to market oil and gas also depends on other factors beyond our control, including:
    the level of domestic production and imports of oil and gas;
 
    the proximity of gas production to gas pipelines;
 
    the availability of pipeline capacity;
 
    the demand for oil and natural gas by utilities and other end users;
 
    the availability of alternate fuel sources;
 
    state and federal regulation of oil and gas marketing; and
 
    federal regulation of gas sold or transported in interstate commerce.
If these factors were to change dramatically, our ability to market oil and gas could be adversely affected.
Our inability to control the inherent risks of acquiring businesses could adversely affect our operations.
Acquisitions have been and we believe will continue to be a key element of our business strategy. We cannot assure you that we will be able to identify and acquire acceptable acquisition candidates on terms favorable to us in the future. We may be required to incur substantial indebtedness to finance future acquisitions. Such additional debt service requirements may impose a significant burden on our results of operations and financial condition. We cannot assure you that we will be able to successfully consolidate the operations and assets of any acquired business with our own business. Acquisitions may not perform as expected when the acquisition was made and may be dilutive to our overall operating results. In addition, our management may not be able to effectively manage our increased size or operate a new line of business.
We may not be able to acquire oil and gas properties to increase our asset utilization.
Our strategy to increase our asset utilization by performing work on our own properties depends on our ability to find, acquire, manage and decommission mature Gulf of Mexico oil and gas properties. Factors that may hinder our ability to acquire these properties include competition, prevailing oil and natural gas prices and the number of properties for sale. Another factor that could hinder our ability to acquire oil and gas properties is our ability to assume additional decommissioning liabilities without posting bonds or providing other financial security to the U.S. Department of Interior, Minerals Management Service, or MMS, or the sellers of these properties, the cost of which may render our proposal unattractive to the sellers. In certain instances, the sellers of these properties may have continuing obligations to us that are unsecured, and although we believe these arrangements represent minimal credit risk, we cannot guarantee that any seller will not become a credit risk in the future. If we are unable to find and acquire properties meeting our criteria on acceptable terms to us, we will not be able to increase the utilization of our assets and services by performing work on our own properties during seasonal downtime and when we have available equipment not being utilized by our traditional customer base. We cannot guarantee that we will be able to locate and acquire such properties.
The nature of our industry subjects us to compliance with regulatory and environmental laws.
Our business is significantly affected by a wide range of local, state and federal statutes, rules, orders and regulations relating to the oil and gas industry in general, and more specifically with respect to the environment, health and safety, waste management and the manufacture, storage, handling and transportation of hazardous wastes. The failure to comply with these rules and regulations can result in the revocation of permits, corrective action orders, administrative or civil penalties and criminal prosecution. Further, laws and regulations in this area are complex and change frequently. Changes in laws or regulations, or their enforcement, could subject us to material costs.
Our oil and gas operations are conducted on federal leases that are administered by MMS and are required to comply with the regulations and orders promulgated by MMS under the Outer Continental Shelf Lands Act. MMS regulations also establish construction requirements for production facilities located on federal offshore leases and govern the plugging and abandonment of wells and the removal of production facilities from these leases. Under limited circumstances, MMS could require us to suspend or terminate our operations on a federal lease. MMS also establishes the basis for royalty payments due under federal oil and natural gas leases through regulations issued under applicable statutory authority.
Our oil and gas operations are also subject to certain requirements under OPA. Under OPA and its implementing regulations, “responsible parties,” including owners and operators of certain vessels and offshore facilities, are strictly liable for damages resulting from spills of oil and other related substances in the United States waters, subject to certain limitations. OPA also requires a responsible party to submit proof of its financial ability to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. Further, OPA

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imposes other requirements, such as the preparation of oil spill response plans. In the event of a substantial oil spill originating from one of our facilities, we could be required to expend potentially significant amounts of capital which could have a material adverse effect on our future operations and financial results.
We have compliance costs and potential environmental liabilities with respect to our offshore and onshore operations, including our environmental cleaning services. Certain environmental laws provide for joint and several liabilities for remediation of spills and releases of hazardous substances. These environmental statutes may impose liability without regard to negligence or fault. In addition, we may be subject to claims alleging personal injury or property damage as a result of alleged exposure to hazardous substances. We believe that our present operations substantially comply with applicable federal and state pollution control and environmental protection laws and regulations. We also believe that compliance with such laws has not had a material adverse effect on our operations. However, we are unable to predict whether environmental laws and regulations will have a material adverse effect on our future operations and financial results. Sanctions for noncompliance may include revocation of permits, corrective action orders, administrative or civil penalties and criminal prosecution.
Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and plugging and abandonment and reports concerning operations. Federal and state laws that also require owners of non-producing wells to plug the well and remove all exposed piping and rigging before the well is permanently abandoned significantly affect the demand for our plug and abandonment services. A decrease in the level of enforcement of such laws and regulations in the future would adversely affect the demand for our services and products. In addition, demand for our services is affected by changing taxes, price controls and other laws and regulations relating to the oil and gas industry generally. The adoption of laws and regulations curtailing exploration and development drilling for oil and gas in our areas of operations for economic, environmental or other policy reasons could also adversely affect our operations by limiting demand for our services.
The regulatory burden on our business increases our costs and, consequently, affects our profitability. We are unable to predict the level of enforcement of existing laws and regulations, how such laws and regulations may be interpreted by enforcement agencies or court rulings, or whether additional laws and regulations will be adopted. We are also unable to predict the effect that any such events may have on us, our business, or our financial condition.
A terrorist attack or armed conflict could harm our business.
Terrorist activities, anti-terrorist efforts and other armed conflict involving the United States may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
Information on properties is contained in Item 1 of this Form 10-K and in note 14 to our consolidated financial statements included in Part II, Item 8.

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Item 3. Legal Proceedings
We are involved in various legal and other proceedings that are incidental to the conduct of our business. We do not believe that any of these proceedings, if adversely determined, would have a material adverse affect on our financial condition, results of operations or cash flows.
Item 4. Submission of Matters to a Vote of Security Holders
None.
Item 4A. Executive Officers of Registrant
Terence E. Hall, age 61, has served as our Chairman of the Board and Chief Executive Officer and as a Director since December 1995. From December 1995 to November 2004, Mr. Hall also served as our President.
Kenneth L. Blanchard, age 57, has served as our President since November 2004, and as our Chief Operating Officer since June 2002. Mr. Blanchard also served as one of our Executive Vice Presidents from December 1995 to November 2004.
Robert S. Taylor, age 52, has served as our Chief Financial Officer since January 1996, as one of our Executive Vice Presidents since September 2004, and as our Treasurer since July 1999. He also served as one of our Vice Presidents from July 1999 to September 2004.
A. Patrick Bernard, age 49, has served as our Senior Executive Vice President of Operations since July 2006 and as one of our Executive Vice Presidents since September 2004. He served as one of our Vice Presidents from June 2003 until September 2004. From July 1999 until June 2003, Mr. Bernard served as the Chief Financial Officer of our wholly-owned subsidiary International Snubbing Services, L.L.C. and its predecessor company.
L. Guy Cook, III, age 38, has served as one of our Executive Vice Presidents since September 2004. He has also served as an Executive Vice President of our wholly-owned subsidiary Superior Energy Services, L.L.C. since May 2006 and a Vice President of this subsidiary and its predecessor company since August 2000. He served as our Director of Investor Relations from April 1997 to February 2000 and was also responsible for integrating our acquisitions during that time.
James A. Holleman, age 49, has served as one of our Executive Vice Presidents since September 2004. He served as one of our Vice Presidents from July 1999 to September 2004. Mr. Holleman has served as an Executive Vice President since May 2006 and as a Vice President since July 1999 of Superior Energy Services, L.L.C. From 1994 until July 1999, he served as the Chief Operating Officer of Cardinal Services, Inc., which we acquired in July 1999 and is the predecessor to Superior Energy Services, L.L.C.
Gregory L. Miller, age 49, has served as one of our Executive Vice Presidents since September 2004. He has also served as the President of our wholly-owned subsidiary SPN Resources, LLC, since April 2003. From January 1991 to April 2003, Mr. Miller served as President and Chief Executive Officer of Optimal Energy, Inc.
Danny R. Young, age 51, has served as one of our Executive Vice Presidents since September 2004. Since May 2006, Mr. Young has served as an Executive Vice President of Superior Energy Services, L.L.C. From January 2002 to May 2005, he served as Vice President of Health, Safety and Environment and Corporate Services of Superior Energy Services, L.L.C.

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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
2005
               
First Quarter
  $ 19.75     $ 14.58  
Second Quarter
    18.46       13.71  
Third Quarter
    24.10       17.64  
Fourth Quarter
    23.98       17.33  
 
               
2006
               
First Quarter
  $ 27.61     $ 21.30  
Second Quarter
    35.87       26.21  
Third Quarter
    35.75       21.44  
Fourth Quarter
    36.48       24.04  
As of February 16, 2007, there were 80,636,962 shares of our common stock outstanding, which were held by 205 record holders.
Dividend Information
We have never paid any cash dividends on our common stock. We currently expect to retain all of the cash our business generates to fund the operation and expansion of our business.
Equity Compensation Plan Information
Information required by this item with respect to compensation plans under which our equity securities are authorized for issuance is incorporated by reference from Part III, Item 12.
Issuer Purchases of Equity Securities
The following table provides information about the common stock repurchased during the quarter ended December 31, 2006 in connection with our offering of 1.5% Senior Exchangeable Notes due 2026:
                                 
                            Approximate  
                            Dollar Value of  
                    Total Number of     Shares that May  
                    Shares Purchased as     Yet be  
    Total Number of     Average Price Paid     Part of Publicly     Purchased  
Period   Shares Purchased     per Share     Announced Plan     Under the Plan  
December 12, 2006
    4,739,300     $ 33.76       4,739,300     $  
 
                       

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Performance Graph
The graph and corresponding table below compares the total stockholder return on our common stock for the last five years with the total return on the S&P 500 Index and a Self-Determined Peer Group for the same period. The information in the graph is based on the assumption of a $100 investment on January 1, 2002 at closing prices on December 31, 2001.
(PERFORMANCE GRAPH)
NOTES:
    The lines represent monthly index levels derived from compounded daily returns that include all dividends.
 
    The indexes are reweighted daily, using the market capitalization on the previous trading day.
 
    If the monthly interval, based on the fiscal year-end, is not a trading day, the preceding trading day is used.
 
    The index level for all series was set to $100.00 on December 31, 2001.
Our Self-Determined Peer Group consists of the same peer group of twelve companies whose average stockholder return levels comprise part of the performance criteria established by the Compensation Committee under our long-term incentive compensation program: BJ Services Company, Helix Energy Solutions Group, Inc., Helmerich & Payne, Inc., Oceaneering International, Inc., Oil States International, Inc., Pride International, Inc., RPC, Inc., Seacor Holdings Inc., Smith International, Inc., Tetra Technologies, Inc., W-H Energy Services, Inc. and Weatherford International, Ltd.

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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,
    2006   2005   2004   2003   2002
Revenues
  $ 1,093,821     $ 735,334     $ 564,339     $ 500,625     $ 443,147  
Income from operations
    316,889       125,603       76,289       67,343       57,021  
Net income
    188,241       67,859       35,852       30,514       21,886  
Net income per share:
                                       
Basic
    2.36       0.87       0.48       0.41       0.30  
Diluted
    2.32       0.85       0.47       0.41       0.30  
Total assets
    1,874,478       1,097,250       1,003,913       832,863       727,620  
Long-term debt, less current portion
    711,505       216,596       244,906       255,516       256,334  
Decommissioning liabilities, less current portion
    87,046       107,641       90,430       18,756        
Stockholders’ equity
    710,688       524,374       433,879       368,129       335,342  

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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, highly diversified provider of oilfield services and equipment. We focus on serving the drilling-related needs of oil and gas companies primarily through our rental tools segment, and the production-related needs of oil and gas companies through our well intervention, rental tools and marine segments. We have expanded geographically so that we now have a growing presence in select domestic land and international market areas. We also own and operate, through our subsidiary SPN Resources, LLC, mature oil and gas properties in the Gulf of Mexico.
The oil and gas industry remains highly cyclical and seasonal. Activity levels in our service and rental tools segments are driven primarily by traditional energy industry activity indicators, which include current and expected commodity prices, drilling rig counts, oil and gas production levels, and customers’ spending allocated for drilling and production.
Several factors contributed to our financial performance in 2006, including:
    increased customer spending levels on finding oil and gas reserves due to high commodity prices;
 
    increased customer focus on replacing reserves and increasing production through production-enhancement projects in existing wells;
 
    growth in our non-Gulf of Mexico market areas; and
 
    extremely high demand in the Gulf of Mexico market area.
The 2004 and 2005 hurricane seasons were a significant catalyst for Gulf of Mexico activity in 2006. First, repair work to damaged platforms and wells created demand for our liftboats, well control, plug and abandonment, project management and engineering services. Second, storm-related disruptions and the associated repair work delayed typical production enhancement projects, creating pent-up demand for our production-related services and liftboats. We experienced additional service work as these production-related projects started to get addressed during the year. Finally, insurance costs for oil and gas operators in the Gulf of Mexico have increased dramatically. As a result, many customers emphasized plugging and abandoning uneconomic wells in an effort to lower their insurance costs. This also drove demand for plug and abandonment services, liftboats and ancillary equipment in 2006.
Revenue from our non-Gulf of Mexico market areas was approximately $439 million, a 49% increase from 2005. More than 60% of this non-Gulf of Mexico revenue, or about $270 million, was generated from domestic land market areas. We continued to aggressively expand our rentals of accommodation units and accessories, drill collars, drill pipe, ancillary tubulars, handling tools and stabilizers into Arkansas, Oklahoma, Texas and the Rocky Mountains market areas. We also expanded our well intervention services to some of these same market areas and experienced activity increases in our existing onshore locations for coiled tubing, mechanical wireline and electric line services.
In 2006, we continued our domestic land and international expansion strategy. We aggressively expanded our rental tools internationally in certain international market areas, including the North Sea, West Africa and the Middle East. In July, we announced the signing of more than $100 million of international contracts. In December, we completed our acquisition of Warrior Energy Services Corporation, which is a provider of production-related services primarily in the major domestic land basins.
Well Intervention Segment

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The well intervention segment consists of specialized down-hole services, which are both labor and equipment intensive. While our gross margin percentage tends to be fairly consistent, projects such as emergency well control work can directly increase the gross margin percentage.
Revenue and income from operations were 38% and 222% higher, respectively, as compared to 2005. This was due mainly to a sharp rebound in Gulf of Mexico activity following significant downtime in 2005 due to hurricanes Katrina and Rita. In the Gulf of Mexico, well control, engineering and plug and abandonment services were utilized in hurricane recovery projects. In addition, activity in the Gulf of Mexico for our production-related services such as coiled tubing, electric line, hydraulic workover, mechanical wireline and pumping and stimulation also experienced significant increases due to an increase in production-related projects. We also grew our non-Gulf of Mexico activity as reflected by a 43% increase in this segment’s non-Gulf of Mexico revenue. These increases were primarily a result of continued domestic land expansion of our production-related services.
Rental Tools Segment
The rental tools segment consists of tools and equipment used in oil and gas drilling and production. This segment is capital and equipment intensive. It is characterized by high gross and operating margins due in part to relatively low operating costs. The largest fixed cost is typically depreciation as there is little labor associated with our rental tools businesses. Historically, pricing has not significantly fluctuated and financial performance is more of a function of changes in volume rather than pricing.
Revenue increased 52% and income from operations increased 107% over 2005. Although pricing tends to be stable, we were able to raise prices for many of our rental tools as a result of robust demand in many of our market areas. The largest activity increases were in the Gulf of Mexico, followed by the domestic land markets areas. Rentals outside the Gulf of Mexico represent more than 60% of this segment’s total revenue in 2006.
Marine Segment
The marine segment consists of our 27 rental liftboats. The operating costs of our liftboats are relatively fixed and, therefore, gross margin percentages vary significantly from quarter-to-quarter and year-to-year primarily based on changes in dayrates and utilization levels. As an indication of this segment’s performance, gross margin percentages were 60% for 2006 primarily due to dayrates that were at their highest levels in our history and high utilization.
Revenue increased 61% and income from operations increased 158% over 2005. Dayrates increased throughout the year as a result of multiple rate increases as our liftboats were used to support hurricane-related projects and to support the increase in traditional production-related activity. As the year progressed, the mix of work for our liftboats shifted away from supporting construction work associated with hurricane recovery projects as demand for production-related projects increased.
Oil and Gas Segment
Through our subsidiary SPN Resources, LLC, we acquire, manage and decommission mature properties in the Outer Continental Shelf of the Gulf of Mexico. As of December 31, 2006, we had interests in 31 offshore blocks containing 65 structures and approximately 156 producing wells.
The main objective of this business segment is to provide additional opportunities for our products and services, especially during cyclical and seasonal slower periods. Because of the relatively high fixed costs of our well intervention services, the incremental cost to work on mature properties is far less than it would be for traditional energy producers. This segment provides work for our services, thereby increasing utilization of our own assets by deploying services on our own properties during periods of downtime.
The lease operating expenses for mature properties are typically relatively high because of the amount of well intervention service work required to enhance, maintain and extend their productive lives.
Revenues were 62% higher and income from operations was 252% higher than 2005. We spent the first several months of the year working to restore production and repair damages caused by the active hurricane season of 2005.

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Production was fully restored by April. We also added production through our second quarter acquisition of five offshore Gulf of Mexico leases. We had approximately 2,505,000 boe of production in 2006 as compared to approximately 1,794,000 boe of production in 2005.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations are based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Note 1 to our consolidated financial statements contains a description of the accounting policies used in the preparation of our financial statements. We evaluate our estimates on an ongoing basis, including those related to long-lived assets and goodwill, income taxes, allowance for doubtful accounts, self-insurance and oil and gas properties. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances. Actual amounts could differ significantly from these estimates under different assumptions and conditions.
We define a critical accounting policy or estimate as one that is both important to our financial condition and results of operations and requires us to make difficult, subjective or complex judgments or estimates about matters that are uncertain. We believe that the following are the critical accounting policies and estimates used in the preparation of our consolidated financial statements. In addition, there are other items within our consolidated financial statements that require estimates but are not deemed critical as defined in this paragraph.
Long-Lived Assets. We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of any such asset may not be recoverable. We record impairment losses on long-lived assets, including oil and gas properties, used in operations when the estimated cash flows to be generated by those assets are less than the carrying amount of those items. Our cash flow estimates are based upon, among other things, historical results adjusted to reflect our best estimate of future market rates, utilization levels, operating performance, and with respect to our oil and gas properties, future oil and natural gas sales prices, an estimate of the ultimate amount of recoverable oil and natural gas reserves that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas and other factors. Our estimates of cash flows may differ from actual cash flows due to, among other things, changes in economic conditions or changes in an asset’s operating performance. If the sum of the cash flows is less than the carrying value, we recognize an impairment loss, measured as the amount by which the carrying value exceeds the fair value of the asset. The net carrying value of assets not fully recoverable is reduced to fair value. Our estimate of fair value represents our best estimate based on industry trends and reference to market transactions and is subject to variability. The oil and gas industry is cyclical and our estimates of the period over which future cash flows will be generated, as well as the predictability of these cash flows, can have significant impact on the carrying value of these assets and, in periods of prolonged down cycles, may result in impairment charges.
Goodwill. In assessing the recoverability of goodwill, we must make assumptions regarding estimated future cash flows and other factors to determine the fair value of the respective assets. If these estimates or their related assumptions adversely change in the future, we may be required to record material impairment charges for these assets not previously recorded. We test goodwill for impairment in accordance with Statement of Financial Accounting Standards No. 142 (FAS No. 142), “Goodwill and Other Intangible Assets.” FAS No. 142 requires that goodwill as well as other intangible assets with indefinite lives no longer be amortized, but instead tested annually for impairment. Our annual testing of goodwill is based on our fair value and carrying value at December 31. We estimate the fair value of each of our reporting units (which are consistent with our reportable segments) using various cash flow and earnings projections. We then compare these fair value estimates to the carrying value of our reporting units. If the fair value of the reporting units exceeds the carrying amount, no impairment loss is recognized. Our estimates of the fair value of these reporting units represent our best estimates based on industry trends and reference to market transactions. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events.
Income Taxes. We provide for income taxes in accordance with Statement of Financial Accounting Standards No. 109 (FAS No. 109), “Accounting for Income Taxes.” This standard takes into account the differences between

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financial statement treatment and tax treatment of certain transactions. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Our deferred tax calculation requires us to make certain estimates about our future operations. Changes in state, federal and foreign tax laws, as well as changes in our financial condition or the carrying value of existing assets and liabilities, could affect these estimates. The effect of a change in tax rates is recognized as income or expense in the period that includes the enactment date.
Allowance for Doubtful Accounts. We maintain an allowance for doubtful accounts for estimated losses resulting from the inability of some of our customers to make required payments. These estimated allowances are periodically reviewed, on a case by case basis, analyzing the 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.
Revenue Recognition. We recognize revenue when services or equipment are provided and collectibility is reasonably assured. Services and rentals are generally provided based on fixed or determinable priced purchase orders or contracts with customers. We contract for marine, well intervention and environmental projects either on a day rate or turnkey basis, with a majority of our projects conducted on a day rate basis. Our rental tools are rented on a day rate basis, and revenue from the sale of equipment is recognized when the equipment is shipped. We are using the percentage-of-completion method for recognizing our revenues and related costs on our contract to construct a derrick barge for a third party. We are estimating the percentage complete utilizing engineering estimates and construction progress. We recognize oil and gas revenue from our interests in producing wells as the commodities are delivered, and the revenue is recorded net of royalties and hedge payments due or inclusive of hedge payments receivable.
Self-Insurance. We self-insure, through deductibles and retentions, up to certain levels for losses related to workers’ compensation, marine protection and indemnity, general liability, property damage, and group medical. With the recent contractions of insurance availability, we have been forced to retain more risk by increasing our self-insurance. We accrue for these liabilities based on estimates of the ultimate cost of claims incurred as of the balance sheet date. We regularly review our estimates of reported and unreported claims and provide for losses through reserves. We also have an actuary review our estimates for losses related to workers’ compensation and group medical on an annual basis. While we believe these estimates are reasonable based on the information available, our financial results could be impacted if litigation trends, claims settlement patterns and future inflation rates are different from our estimates. Although we believe adequate reserves have been provided for expected liabilities arising from our self-insured obligations, and we believe that we maintain adequate insurance coverage, we cannot assure that such coverage will adequately protect us against liability from all potential consequences.
Oil and Gas Properties. Our subsidiary, SPN Resources, LLC, acquires mature oil and gas properties and assumes the related well abandonment and decommissioning liabilities. We follow the successful efforts method of accounting for our investment in oil and natural gas properties. Under the successful efforts method, the costs of successful exploratory wells and leases containing productive reserves are capitalized. Costs incurred to drill and equip developmental wells, including unsuccessful development wells, are capitalized. Other costs such as geological and geophysical costs and the drilling costs of unsuccessful exploratory wells are expensed. SPN Resources’ property purchases are recorded at the value exchanged at closing, combined with an estimate of its proportionate share of the decommissioning liability assumed in the purchase. All capitalized costs are accumulated and recorded separately for each field and allocated to leasehold costs and well costs. Leasehold costs are depleted on a units-of-production basis based on the estimated remaining equivalent proved oil and gas reserves of each field. Well costs are depleted on a units-of-production basis based on the estimated remaining equivalent proved developed oil and gas reserves of each field.
We estimate the third party market price to plug and abandon wells, abandon the pipelines, decommission and remove the platforms and clear the sites, and use that estimate to record our proportionate share of the decommissioning liability. In estimating the decommissioning liabilities, we perform detailed estimating procedures, analysis and engineering studies. Whenever practical, we will utilize the services of our subsidiaries to

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perform well abandonment and decommissioning work. When these services are performed by our subsidiaries, all recorded intercompany revenues and expenses are eliminated in the consolidated financial statements. The recorded decommissioning liability associated with a specific property is fully extinguished when the property is completely abandoned. The liability is first reduced by all cash expenses incurred to abandon and decommission the property. If the liability exceeds (or is less than) our incurred costs, the difference is reported as income (or loss) in the period in which the work is performed. We review the adequacy of our decommissioning liability whenever indicators suggest that the estimated cash flows underlying the liability have changed materially. The timing and amounts of these cash flows are subject to changes in the energy industry environment and may result in additional liabilities recorded, which in turn would increase the carrying values of the related properties.
Oil and gas properties are assessed for impairment in value on a field-by-field basis whenever indicators become evident. We use our current estimate of future revenues and operating expenses to test the capitalized costs for impairment. In the event net undiscounted cash flows are less than the carrying value, an impairment loss is recorded based on the present value of expected future net cash flows over the economic lives of the reserves.
Proved Reserve Estimates. Our reserve information is prepared by independent reserve engineers in accordance with guidelines established by the Securities and Exchange Commission. There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control such as commodity pricing. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that can not be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. In accordance with the Securities and Exchange 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.
Comparison of the Results of Operations for the Years Ended December 31, 2006 and 2005
For the year ended December 31, 2006, our revenues were $1,093.8 million, resulting in net income of $188.2 million or $2.32 diluted earnings per share. Our net income includes a loss on early extinguishment of debt of $12.6 million. For the year ended December 31, 2005, revenues were $735.3 million, and net income was $67.9 million or $0.85 diluted earnings per share. We experienced significantly higher revenues and gross margins for our well intervention, rental tools and marine segments due to higher pricing and utilization for most products and services offered. Factors driving our improved performance include higher commodity prices resulting in additional production and drilling-related activity worldwide, as well as demand for our services and liftboats that are necessary to assist in repair work needed as the result of the active Gulf of Mexico hurricane seasons of 2004 and 2005.
The following table compares our operating results for the years ended December 31, 2006 and 2005. Gross margin is calculated by subtracting cost of services from revenue for each of our four business segments. Oil and gas eliminations represent products and services provided to the oil and gas segment by the Company’s other three segments.
                                                                 
    Revenue   Gross Margin
    2006   2005   Change   2006   %   2005   %   Change
         
Well Intervention
  $ 469,110     $ 339,609     $ 129,501     $ 199,479       43 %   $ 125,971       37 %   $ 73,508  
Rental Tools
    371,155       243,536       127,619       255,257       69 %     160,974       66 %     94,283  
Marine
    140,115       87,267       52,848       83,926       60 %     39,278       45 %     44,648  
Oil and Gas
    127,682       78,911       48,771       57,654       45 %     33,107       42 %     24,547  
Less: Oil and Gas Elim.
    (14,241 )     (13,989 )     (252 )                              
         
 
                                                               
Total
  $ 1,093,821     $ 735,334     $ 358,487     $ 596,316       55 %   $ 359,330       49 %   $ 236,986  
         
The following discussion analyzes our results on a segment basis.

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Well Intervention Segment
Revenue for our well intervention segment was $469.1 million for the year ended December 31, 2006, as compared to $339.6 million for 2005. This segment’s gross margin percentage increased to 43% in 2006 from 37% in 2005. We experienced higher revenue for most of our production-related services as pricing and utilization were higher due to increased demand for production-related services and hurricane-related repair work in the Gulf of Mexico. In addition, revenue increased for our plug and abandonment services as many customers continue to plug severely damaged wells and temporarily or permanently plug other wells to lower their insurance exposure and risk of damage from any future hurricanes. We also increased our revenues in the domestic onshore markets and acquired Warrior Energy Services Corporation in December 2006 to further this expansion and strengthen this segment.
Rental Tools Segment
Revenue for our rental tools segment for 2006 was $371.2 million, a 52% increase over 2005. The gross margin percentage increased to 69% in 2006 from 66% in 2005. We experienced significant increases in revenue from our stabilizers, on-site accommodations, drill pipe and accessories, specialty tubulars and drill collars. The increases are primarily the result of significant increases in activity in the Gulf of Mexico, domestic land markets, as well as our international expansion efforts. Our international revenue for the rental tools segment has increased 73% to approximately $95 million for 2006 over 2005.
Marine Segment
Our marine segment revenue for the year ended December 31, 2006 increased 61% over 2005 to $140.1 million. The gross margin percentage for 2006 increased to 60% from 45% in 2005. The year ended December 31, 2006 was characterized by a significant increase in liftboat pricing and utilization due to increased demand resulting from increases in Gulf of Mexico production-related activity and ongoing construction and repair work as a result of the damage in the Gulf of Mexico from Hurricanes Katrina and Rita. The fleet’s average dayrate increased over 80% to approximately $16,600 in 2006 from $9,200 in 2005. The fleet’s average utilization increased to approximately 82% in 2006 from 78% in 2005. The year ended December 31, 2005 also included five months of rental activity from the 105-foot and the 120 to 135-foot class liftboats, which were sold June 1, 2005.
Oil and Gas Segment
Oil and gas revenues were $127.7 million in the year ended December 31, 2006, as compared to $78.9 million in 2005. In 2006, production was approximately 2,505,000 boe, as compared to approximately 1,794,000 boe in 2005. The gross margin percentage increased to 45% in 2006 from 42% in 2005 due to increased production and commodity prices, despite increased insurance cost and repair costs related to Hurricanes Katrina and Rita. The oil and gas segment also benefited from the additional production as a result of the acquisition of the offshore Gulf of Mexico leases in April 2006.
Depreciation, Depletion, Amortization and Accretion
Depreciation, depletion, amortization and accretion increased to $111.0 million in the year ended December 31, 2006 from $89.3 million in 2005. The increase results from the depreciation associated with our 2006 and 2005 capital expenditures primarily in the rental tools segment, as well as additional depletion associated with increased oil and gas production.
General and Administrative Expenses
General and administrative expenses increased to $168.4 million for the year ended December 31, 2006 from $141.0 million in 2005. This increase was primarily attributable to increased expense related to our continued growth through expanding our geographic area of operations and acquisitions as well as increased incentive compensation expense due to our strong operating results. General and administrative expenses decreased to 15% of revenue for 2006 from 19% in 2005.

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Comparison of the Results of Operations for the Years Ended December 31, 2005 and 2004
For the year ended December 31, 2005, our revenues were $735.3 million resulting in net income of $67.9 million or $0.85 diluted earnings per share. For the year ended December 31, 2004, revenues were $564.3 million and net income was $35.9 million or $0.47 diluted earnings per share. We experienced higher revenue and gross margin in all our segments, especially our rental tools, oil and gas and well intervention segments as activity levels increased. However, the extraordinarily active hurricane season disrupted most of our activity for several months following Hurricanes Katrina and Rita.
The following table compares our operating results for the years ended December 31, 2005 and 2004. Gross margin is calculated by subtracting cost of services from revenue for each of our four business segments. Oil and gas eliminations represent products and services provided to the oil and gas segment by the Company’s three other segments.
                                                                 
    Revenue   Gross Margin
    2005   2004   Change   2005   %   2004   %   Change
         
Well Intervention
  $ 339,609     $ 295,690     $ 43,919     $ 125,971       37 %   $ 105,832       36 %   $ 20,139  
Rental Tools
    243,536       170,064       73,472       160,974       66 %     112,711       66 %     48,263  
Marine
    87,267       69,808       17,459       39,278       45 %     20,227       29 %     19,051  
Oil and Gas
    78,911       37,008       41,903       33,107       42 %     15,461       42 %     17,646  
Less: Oil and Gas Elim.
    (13,989 )     (8,231 )     (5,758 )                              
         
 
                                                               
Total
  $ 735,334     $ 564,339     $ 170,995     $ 359,330       49 %   $ 254,231       45 %   $ 105,099  
         
The following discussion analyzes our operating results on a segment basis.
Well Intervention Segment
Revenue for our well intervention segment was $339.6 million for the year ended December 31, 2005, as compared to $295.7 million for 2004. This segment’s gross margin percentage increased slightly to 37% in 2005 from 36% in 2004. We experienced higher revenue for almost all of our services as production-related activity improved in the Gulf of Mexico, particularly for the well control, hydraulic workover, coiled tubing, wireline and field management services. Activity levels declined in the months following Hurricanes Katrina and Rita, but pre-storm demand levels returned near the end of the year.
Rental Tools Segment
Revenue for our rental tools segment for the year ended December 31, 2005 was $243.5 million, a 43% increase over 2004. The gross margin percentage remained unchanged at 66% for the years ended December 31, 2005 and 2004. We experienced significant increases in revenue from our on-site accommodations, drill pipe and accessories and stabilizers. The increases are primarily the result of significant increases in activity in the Gulf of Mexico, as well as our international and domestic expansion efforts. Although our rental tools segment was negatively impacted from Hurricanes Katrina and Rita in August and September of 2005, activity levels surpassed pre-storm levels for most of our rental tools by the end of the year. Our international revenue for the rental tools segment has increased 108% to approximately $53.6 million for the year ended December 31, 2005 from 2004. Our biggest improvements were in the North Sea, Trinidad, Venezuela and Mexico.
Marine Segment
Our marine segment revenue for the year ended December 31, 2005 increased 25% over 2004 to $87.3 million. The gross margin percentage for the year ended December 31, 2005 increased to 45% from 29% for 2004. The year ended December 31, 2005 includes only five months of rental activity from the 105-foot and the 120 to 135-foot class liftboats. These 17 rental liftboats were sold effective June 1, 2005. The increase in revenue is caused by increased utilization of our fleet’s remaining larger liftboats at higher dayrates partially offset by fewer liftboats generating revenue for seven months of 2005. The increase in the gross margin percentage is also caused by

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increased demand and the sale of our lower margin rental liftboats. The fleet’s average dayrate increased 47% to approximately $9,200 in the year ended December 31, 2005 from approximately $6,300 in 2004. Increased demand as well as the sale of the smaller liftboats also contributed to the increase in average dayrates. The fleet’s average utilization increased to approximately 78% for the year ended December 31, 2005 from 72% in 2004. Our liftboat fleet experienced strong increases in demand and pricing in the fourth quarter as liftboats were needed for the large amount of construction and repair work in the Gulf of Mexico as a result of hurricane damage.
Oil and Gas Segment
Oil and gas revenues were $78.9 million in the year ended December 31, 2005 as compared to $37.0 million in 2004. The increase in revenue is primarily the result of production from South Pass 60, which was acquired in July 2004, and production from West Delta 79/86, which was acquired in December 2004. We also acquired Galveston 241/255 and High Island A-309 in late-July 2005. In the year ended December 31, 2005, production was approximately 1,794,000 boe as compared to approximately 918,000 boe in 2004. The gross margin percentage remained unchanged at 42% for the years ended December 31, 2005 and 2004. The oil and gas segment was affected by significant amounts of curtailed production resulting from the active hurricane seasons the past two years resulting in deferred production as a result of Hurricanes Katrina and Rita in 2005 of approximately 744,000 boe and as a result of Hurricane Ivan in 2004 of approximately 347,000 boe.
Depreciation, Depletion, Amortization and Accretion
Depreciation, depletion, amortization and accretion increased to $89.3 million in the year ended December 31, 2005 from $67.3 million in 2004. The increase is primarily a result of depletion and accretion related to our oil and gas properties from both increased production and acquisitions of oil and gas properties. The increase also results from the depreciation associated with our 2005 and 2004 capital expenditures primarily in the rental tools segment.
General and Administrative
General and administrative expenses increased to $141.0 million for the year ended December 31, 2005 from $110.6 million in 2004. Of this increase, $5.5 million is the result of storm-related costs from Hurricanes Katrina and Rita in the third and fourth quarters of 2005 including $2.1 million in equipment and facility losses and repairs, $2.0 million in relief aid to more than 560 employees affected by the hurricanes and $1.4 million in storm-related payroll expenses, temporary lodging and miscellaneous expenses. The remaining increase was primarily related to increased payroll and bonus expenses, increased insurance costs and expenses as a result of our growth, oil and gas acquisitions and geographic expansion.
Reduction in Value of Assets
During the year ended December 31, 2005, we reduced the value of two of our mature oil and gas properties by approximately $2.1 million, thereby removing the reserve balance associated with these wells. The wells were deemed to be uneconomical to further produce as a result of the estimated costs associated with maintaining production.
Our oil spill containment boom manufacturing facility suffered damage from Hurricane Katrina and experienced difficulty in resuming normal business operations. As a result, we elected not to reopen this manufacturing facility and sell the remaining oil spill containment boom inventory. We reduced the value of the assets of this business (which consist primarily of inventory and property and equipment) by approximately $1.1 million to the estimated net realizable value.
In the first quarter of 2006, we sold our environmental subsidiary for approximately $18.7 million in cash. We reduced the net asset value of this subsidiary by $3.8 million in 2005 to its approximate sales price.
Gain on Sale of Liftboats
Effective June 1, 2005, we sold all of our rental liftboats with leg-lengths from 105 feet to 135 feet for $19.8 million in cash (exclusive of costs to sell), which resulted in a gain of $3.5 million.

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Liquidity and Capital Resources
In the year ended December 31, 2006, we generated net cash from operating activities of $280.2 million as compared to $158.4 million in 2005. Our primary liquidity needs are for working capital, capital expenditures, acquisitions and debt service. Our primary sources of liquidity are cash flows from operations and borrowings under our revolving credit facility. We also issued $300 million of 6 7/8% Senior Notes and $400 million of 1.5% Senior Exchangeable Notes to satisfy our liquidity needs in 2006. We had cash and cash equivalents of $39.0 million at December 31, 2006 compared to $54.5 million at December 31, 2005.
We made approximately $242.9 million of capital expenditures during the year ended December 31, 2006, of which approximately $109.6 million was used to expand and maintain our rental tool equipment inventory. We also made $64.3 million of capital expenditures in our oil and gas segment and $65.2 million of capital expenditures to expand and maintain the asset base of our well intervention and marine segments, including $5.9 million related to anchor handling tugs, $20.6 million related to the completion of our first derrick barge and $3.1 million of progress payments related to the construction of another derrick barge. In addition, we made $3.8 million of capital expenditures on construction and improvements to our facilities.
On December 12, 2006, we acquired Warrior Energy Services Corporation for a total purchase price of approximately $374.1 million. The total consideration was comprised of cash payments of $237.8 million (including acquisition costs and repayment of debt) and equity consideration of $136.3 million (5,369,888 shares of Superior common stock valued at $25.39 per share, the average closing market price per share for the five trading day period beginning two trading days before the merger announcement date of September 25, 2006). Warrior is an oil and gas services company that provides various well intervention services and rental tools and equipment onshore in Alabama, Arkansas, Colorado, Kansas, Louisiana, Mississippi, Montana, New Mexico, North Dakota, Oklahoma, Texas, Utah and Wyoming, and offshore in the Gulf of Mexico.
We acquired a 40% interest in Coldren Resources which acquired substantially all of Noble’s shallow water Gulf of Mexico oil and gas properties in July 2006. We have made a total cash investment in Coldren Resources of approximately $57.8 million as of December 31, 2006. We do not anticipate additional cash investments in Coldren Resources.
During the year ended December 31, 2006, we paid $46.6 million to acquire producing oil and gas properties located on five offshore Gulf of Mexico leases and purchased two businesses for approximately $9.8 million. We also sold our environmental cleaning subsidiary for approximately $18.7 million during the first quarter of 2006.
In July 2006, we took delivery of an 880-ton derrick barge. The final payment of $13.3 million was made upon its delivery and acceptance. The derrick barge and related anchor handling tug are chartered to a third party until October 31, 2007.
In July 2006, we contracted to construct a derrick barge that will be sold to a third party for approximately $54 million. We expect to take delivery of the derrick barge and sell it to the third party during the first quarter of 2008. We receive monthly payments from the purchaser in accordance with the terms of the sales contract. In turn, we issue letters of credit to the purchaser in equal amounts to guarantee our performance of the contract. We have entered into fixed-price contracts to construct this second derrick barge and its 880-ton offshore mast crane. Our payment obligation for the construction of the barge is secured by letters of credit that are posted upon performance milestones and are payable upon the barge’s delivery and our acceptance. The contract for the crane requires periodic progress payments with final payment due upon completion of the contract. Revenue and costs associated with the sale contract are accounted for on the percentage-of-completion method utilizing engineering estimates and construction progress. This methodology requires us to make estimates regarding our progress against the project schedule and estimated completion date, both of which impact the amount of revenue and gross margin we recognize in each reporting period. Contract costs mainly include sub-contract and program management costs. Provisions for any anticipated losses will be recorded in full when such losses become evident.
In July 2006, we contracted to construct a third derrick barge to support our decommissioning and construction operations. We expect to take delivery of this barge in the second quarter of 2008. We have entered into fixed-price

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contracts to construct this derrick barge and its 880-ton offshore mast crane. Our payment obligation for the construction of the barge is secured by letters of credit that are posted upon performance milestones and are payable upon the barge’s delivery and our acceptance. The contract for the crane requires periodic progress payments with final payment due upon completion of the contract. We currently intend to utilize this construction barge to support our removal projects in the Gulf of Mexico market area for both third party customers and our subsidiary, SPN Resources.
We amended our revolving credit facility in the fourth quarter of 2006 increasing it to $250 million from $150 million. Any amounts outstanding under the revolving credit facility are due on June 14, 2011. At February 16, 2006, we had $27.1 million outstanding under the bank credit facility at an interest rate of 7.6% per annum. We also had approximately $54.5 million of letters of credit outstanding, which reduces our borrowing capacity under this credit facility. Borrowings under the credit facility bear interest at a LIBOR rate plus margins that depend on our leverage ratio. Indebtedness under the credit facility is secured by substantially all of our assets, including the pledge of the stock of our principal subsidiaries. The credit facility contains customary events of default and requires that we satisfy various financial covenants. It also limits our ability to pay dividends or make other distributions, make acquisitions, create liens, incur additional indebtedness or assume additional decommissioning liabilities.
We have $16.6 million outstanding at December 31, 2006 in U. S. Government guaranteed long-term financing under Title XI of the Merchant Marine Act of 1936, which is administered by the Maritime Administration (MARAD), for two 245-foot class liftboats. This debt bears an interest rate of 6.45% per annum and is payable in equal semi-annual installments of $405,000 on every June 3rd and December 3rd through June 3, 2027. Our obligations are secured by mortgages on the two liftboats. This MARAD financing also requires that we comply with certain covenants and restrictions, including the maintenance of minimum net worth and debt-to-equity requirements.
In the second quarter of 2006, we completed a tender offer for approximately 97.6% of our $200 million outstanding of 8 7/8% unsecured senior notes due 2011. The cash consideration for the tender offer was $1,045.63 per $1,000 in aggregate principal amount of senior notes tendered. In conjunction with the tender offer, we also received consents to amend the indenture pursuant to which the senior notes were issued to eliminate from the indenture substantially all of the restrictive covenants and certain events of default. After the tender offer was completed, we redeemed the remaining outstanding senior notes in accordance with the indenture at the redemption price of $1,044.38 per $1,000 of the principal amount redeemed. We recognized a loss on the early extinguishment of debt of approximately $12.6 million, which included the tender premiums, redemption premiums, fees and expenses and the write-off of the remaining unamortized debt acquisition costs associated with these notes.
We issued $300 million of 6 7/8% unsecured senior notes due 2014. We used the net proceeds to refinance the 8 7/8% senior notes due 2011 and related tender and redemption premiums, fees and related expenses, and to fund the equity investment in Coldren Resources. The indenture governing the notes requires semi-annual interest payments, on every June 1st and December 1st through the maturity date of June 1, 2014. The indenture contains certain covenants that, among other things, restrict us from incurring, additional debt, repurchasing capital stock, paying dividends or making other distributions, incurring liens, selling assets or entering into certain mergers or acquisitions.
In December 2006, we issued $400 million of 1.50% Senior Exchangeable Notes due 2026. The notes bear interest at a rate of 1.50% per annum and decrease to 1.25% per annum on December 15, 2011. Interest on the notes is payable semi-annually in arrears on December 15th and June 15th of each year, beginning June 15, 2007. The notes do not contain any restrictive financial covenants.
Under certain circumstances, holders may exchange the notes for shares of our common stock. The initial exchange rate is 21.9414 shares of common stock per $1,000 principal amount of notes. This is equal to an initial exchange price of $45.58 per share. The exchange price represents a 35% premium over the closing share price at the date of issuance. The notes may be exchanged under the following circumstances:
    during any fiscal quarter (and only during such fiscal quarter) commencing after March 31, 2007, if the last reported sale price of our common stock is greater than or equal to 135% of the applicable exchange price

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      of the notes for at least 20 trading days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter;
 
    prior to December 15, 2011, during the five business-day period after any ten consecutive trading-day period (the “measurement period”) in which the trading price of $1,000 principal amount of notes for each trading day in the measurement period was less than 95% of the product of the last reported sale price of our common stock and the exchange rate on such trading day;
 
    if the notes have been called for redemption;
 
    upon the occurrence of specified corporate transactions; or
 
    at any time beginning on September 15, 2026, and ending at the close of business on the second business day immediately preceding the maturity date.
In connection with the exchangeable note transaction, we simultaneously entered into agreements with affiliates of the initial purchasers to purchase call options and sell warrants on our common stock. We may exercise the call options we purchased at any time to acquire approximately 8.8 million shares of our common stock at a strike price of $45.58 per share. The owners of the warrants may exercise the warrants to purchase from us approximately 8.8 million shares of our common stock at a price of $59.42 per share, subject to certain anti-dilution and other customary adjustments. The warrants may be settled in cash, in shares or in a combination of cash and shares, at our option. These transactions may potentially reduce the dilution of our common stock from the exchange of the notes by increasing the effective exchange price to $59.42 per share. We paid $96 million (exclusive of a $35.5 million tax benefit) to acquire the call options and received $60.4 million as a result of the sale of the warrants.
In December 2006, concurrently with the closing of our 1.5% Senior Exchangeable Notes, we repurchased 4,739,300 shares of our outstanding common stock at a price of $33.76 per share, or approximately $160 million in the aggregate, in privately negotiated block trades through one of the initial purchasers of the notes.
The following table summarizes our contractual cash obligations and commercial commitments at December 31, 2006 (amounts in thousands) for our long-term debt (including estimated interest payments), decommissioning liabilities, operating leases and contractual obligations. The decommissioning liability amounts do not give any effect to our contractual right to receive amounts from third parties, which is approximately $31.0 million, when decommissioning operations are performed. The derrick barge and tug construction obligation amounts do not give any effect to our contractual right to receive payments from a third-party customer, which is approximately $41.2 million. We do not have any other material obligations or commitments.
                                                 
Description   2007   2008   2009   2010   2011   Thereafter
 
Long-term debt, including estimated interest payments
  $ 28,492     $ 28,440     $ 28,388     $ 28,336     $ 27,783     $ 845,578  
Decommissioning liabilities
    35,150       5,743       2,371       10,271       29,390       39,271  
Operating leases
    7,003       4,939       2,932       1,628       973       13,692  
Derrick barge and tug construction
    26,332       45,562                          
     
 
                                               
Total
  $ 96,977     $ 84,684     $ 33,691     $ 40,235     $ 58,146     $ 898,541  
     
We have no off-balance sheet arrangements other than our potential additional consideration that may be payable as a result of the future operating performances of our acquisitions. At December 31, 2006, the maximum additional consideration payable for our prior acquisitions was approximately $2.4 million. These amounts are not classified as liabilities under generally accepted accounting principles and are not reflected in our financial statements until the amounts are fixed and determinable. When amounts are determined, they are capitalized as part of the purchase price of the related acquisition. We do not have any other financing arrangements that are not required under generally accepted accounting principles to be reflected in our financial statements.
We currently believe that we will make approximately $362 million of capital expenditures, excluding acquisitions and targeted asset purchases, during 2007 to expand our rental tool asset base, add new coiled tubing and electric-line units, construct our derrick barges and perform workovers on SPN Resources’ oil and gas properties. We

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believe that our current working capital, cash generated from our operations and availability under our revolving credit facility will provide sufficient funds for our identified capital projects.
We intend to continue implementing our growth strategy of increasing our scope of services through both internal growth and strategic acquisitions. We expect to continue to make the capital expenditures required to implement our growth strategy in amounts consistent with the amount of cash generated from operating activities, the availability of additional financing and our credit facility. Depending on the size of any future acquisitions, we may require additional equity or debt financing in excess of our current working capital and amounts available under our revolving credit facility.
Hedging Activities
We entered into hedging transactions in 2004 that expired on August 31, 2006 to secure a commodity price for a portion of our oil production and to reduce our exposure to oil price fluctuations. We do not enter into derivative transactions for trading purposes. We used financially-settled crude oil swaps and zero-cost collars that provided floor and ceiling prices with varying upside price participation. Our swaps and zero-cost collars were designated and accounted for as cash flow hedges. We have not hedged any of our natural gas production. We recognized the fair value of all derivative instruments as assets or liabilities on the balance sheet. Changes in the fair value of cash flow hedges, to the extent the hedge was effective, were recognized in other comprehensive income until the hedged item was settled and recorded in oil and gas revenues. For the year ended December 31, 2006, hedging settlement payments reduced oil and gas revenues by approximately $13.8 million, and no gains or losses were recognized due to hedge ineffectiveness.
Recently Issued Accounting Pronouncements
In February 2006, the Financial Accounting Standards Board issued its Statement of Financial Accounting Standards No. 155 (FAS No. 155), “Accounting for Certain Hybrid Financial Instruments – an amendment of FASB Statements No. 133 and 140.” FAS No. 155 simplifies accounting for certain hybrid financial instruments by permitting fair value remeasurement for any hybrid instrument that contains an embedded derivative that otherwise would require bifurcation and eliminates a restriction on the passive derivative instruments that a qualifying special-purpose entity may hold. FAS No. 155 is effective for all financial instruments acquired, issued or subject to a remeasurement (new basis) event occurring after the beginning of an entity’s first fiscal year that begins after September 15, 2006. The adoption of FAS No. 155 has not had an impact on our results of operations or our financial position.
In July 2006, the Financial Accounting Standards Board issued FASB Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109.” FIN 48 provides guidance on measurement and recognition in accounting for income tax uncertainties and also requires expanded financial statement disclosure. This interpretation is effective for fiscal years beginning after December 15, 2006. We have evaluated the impact of FIN 48 and do not expect it to have a material impact on our results of operations or financial condition.
In September 2006, the Financial Accounting Standards Board issued its Statement of Financial Accounting Standards No. 157 (FAS No. 157), “Fair Value Measurements.” FAS No. 157 establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. FAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. We are currently evaluating the impact that FAS No. 157 will have on our results of operations and financial position.
In September 2006, the Financial Accounting Standards Board issued its Statement of Financial Accounting Standards No. 158 (FAS No. 158), “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – an Amendment of FASB Statements No. 87, 88, 106, and 132(R).” FAS No. 158 requires recognition of the overfunded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability on the balance sheet and the recognition of changes in the funded status in the year in which the changes occur though comprehensive income. FAS No. 158 also requires an employer to measure the funded status of a plan as of the end of the fiscal year. FAS No. 158 is effective for fiscal years ending after December 15, 2006,

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except for the measurement date provisions which are effective for fiscal years ending after December 15, 2008. The adoption of FAS No. 158 has not had an impact on our results of operations or our financial position.
In September 2006, the Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin No. 108 (SAB 108), “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements.” SAB 108 provides guidance on the consideration of effects of prior year misstatements in quantifying current year misstatements for the purpose of a materiality assessment. SAB 108 requires the analysis of misstatements using both a balance sheet and income statement approach and contains guidance on correcting errors under the dual approach, as well as providing transition guidance for correcting errors existing in prior years. SAB 108 is effective for the first fiscal year ending after November 15, 2006, with early application encouraged. The adoption of SAB 108 did not have a material impact on our results of operations or financial position.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
We are exposed to market risks associated with foreign currency fluctuations and changes in interest rates. A discussion of our market risk exposure in financial instruments follows.
Foreign Currency Exchange Rates
Because we operate in a number of countries throughout the world, we conduct a portion of our business in currencies other than the U.S. dollar. The functional currency for our international operations, other than our operations in the United Kingdom, is the U.S. dollar, but a portion of the revenues from our foreign operations is paid in foreign currencies. The effects of foreign currency fluctuations are partly mitigated because local expenses of such foreign operations are also generally denominated in the same currency. We continually monitor the currency exchange risks associated with all contracts not denominated in the U.S. dollar. Any gains or losses associated with such fluctuations have not been material.
We do not hold any foreign currency exchange forward contracts and/or currency options. We have not made use of derivative financial instruments to manage risks associated with existing or anticipated transactions. We do not hold derivatives for trading purposes or use derivatives with complex features. Assets and liabilities of our subsidiary in the United Kingdom are translated at current exchange rates, while income and expense are translated at average rates for the period. Translation gains and losses are reported as the foreign currency translation component of accumulated other comprehensive income in stockholders’ equity.
Interest Rates
At December 31, 2006, none of our long-term debt outstanding had variable interest rates, and we had no interest rate risks at that time.
Equity Price Risk
In December 2006, we issued $400 million of 1.50% Senior Exchangeable Notes due 2026 in a private offering to qualified institutional buyers. The notes are, subject to the occurence of specified conditions, exchangeable for our common stock initially at an exchange price of $45.58 per share, which would result in an aggregate of approximately 8.8 million shares of common stock being issued upon exchange. We may redeem for cash all or any part of the notes on or after December 15, 2011 for 100% of the principal amount redeemed. The holders may require us to repurchase for cash all or any portion of the notes on December 15, 2011, December 15, 2016 and December 15, 2021 for 100% of the principal amount of notes to be purchased plus any accrued and unpaid interest. The notes do not contain any restrictive financial covenants.
Each $1,000 of principal amount of the notes is initially exchangeable into 21.9414 shares of our common stock, subject to adjustment upon the occurrence of specified events. Holders of the notes may exchange their notes prior to maturity only if: (1) the price of our common stock reaches $45.58 during certain periods of time specified in the notes; (2) specified corporate transactions occur; (3) the notes have been called for redemption; or (4) the trading price of the notes falls below a certain threshold. In addition, in the event of a fundamental change in our corporate

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ownership or structure, the holders may require us to repurchase all or any portion of the notes for 100% of the principal amount.
Concurrently with the issuance of the notes, we entered into agreements with affiliates of the initial purchasers to purchase call options and sell warrants of our common stock. We may exercise the call options at any time to acquire approximately 8.8 million shares of our common stock at a strike price of $45.58 per share. The owners of the warrants may exercise their warrants to purchase from us approximately 8.8 million shares of our common stock at a price of $59.42 per share, subject to certain anti-dilution and other customary adjustments. The warrants may be settled in cash, in shares or in a combination of cash and shares, at our option. We paid $96 million (exclusive of a $35.5 million tax benefit) to acquire the call options and received $60.4 million as a result of the sale of the warrants.
For additional discussion of the notes, see “Managements’ Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” in Part II, Item 7 above.
Commodity Price Risk
Our revenues, profitability and future rate of growth partially depends upon the market prices of oil and natural gas. Lower prices may also reduce the amount of oil and gas that can economically be produced.
We use derivative commodity instruments to manage commodity price risks associated with future oil production. We have not hedged any of our natural gas production. Our hedging contracts for a portion of our oil production expired on August 31, 2006, and there are no outstanding contracts as of December 31, 2006 or as of the date of this Form 10-K.

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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. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with generally accepted accounting principles.
Our system of internal control over financial reporting includes policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the financial statements.
In assessing the effectiveness of our internal control over financial reporting as of December 31, 2006, we have excluded Warrior Energy Services Corporation, which we acquired on December 12, 2006. Warrior Energy Services Corporation’s total assets were $451.8 million, or approximately 24% of our total assets, as of December 31, 2006, and Warrior Energy Services Corporation’s total revenues were $7.7 million, or approximately 1% of our total revenues, for the year ended December 31, 2006.
Our management, including our principal executive officer and principal financial officer, performed an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2006 based upon criteria in “Internal Control – Integrated Framework,” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, our management determined that our internal control over financial reporting was effective as of December 31, 2006.
Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2006 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which appears herein which expresses unqualified opinions on our management’s assessment and on the effectiveness of our internal control over financial reporting as of December 31, 2006.

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Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Superior Energy Services, Inc.:
We have audited the accompanying consolidated balance sheets of Superior Energy Services, Inc. and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2006. In connection with our audit of the consolidated financial statements, we also have audited the accompanying financial statement schedule, “Valuation and Qualifying Accounts,” for the years ended December 31, 2006, 2005 and 2004. These consolidated financial statements and financial statement schedule are the responsibility of the 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, 2006 and 2005, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
As discussed in note 3 to the consolidated financial statements, the Company changed its method of accounting for share-based compensation.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Superior Energy Services, Inc.’s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 28, 2007 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.
         
  KPMG LLP
 
 
     
     
     
 
New Orleans, Louisiana
February 28, 2007

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Report of Independent Registered Public Accounting Firm
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, 2006, 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, 2006, 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, 2006, 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. acquired Warrior Energy Services Corporation on December 12, 2006, and management excluded from its assessment of the effectiveness of Superior Energy Services, Inc.’s internal control over financial reporting as of December 31, 2006, Warrior Energy Services Corporation’s internal control over financial reporting associated with total assets of $451.8 million, or approximately 24% of the Company’s total assets, and total revenues of $7.7 million , or approximately 1% of the Company’s total revenues included in the consolidated financial statements of Superior Energy Services, Inc. and subsidiaries as of and for the year ended December 31, 2006. Our audit of internal control over financial reporting of Superior Energy Services, Inc. also excluded an evaluation of the internal control over financial reporting of Warrior Energy Services Corporation.

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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, 2006 and 2005, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2006. Our report dated February 28, 2007 expressed an unqualified opinion on those consolidated financial statements. Our report for the year ended December 31, 2006 refers to a change in the method of accounting for share-based payments.
         
  KPMG, LLP
 
 
     
     
     
 
New Orleans, Louisiana
February 28, 2007

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
December 31, 2006 and 2005
(in thousands, except share data)
                 
    2006     2005  
ASSETS
               
 
               
Current assets:
               
Cash and cash equivalents
  $ 38,970     $ 54,457  
Accounts receivable, net of allowance for doubtful accounts of $17,419 and $11,569 at December 31, 2006 and 2005, respectively
    303,800       196,365  
Income taxes receivable
    2,630        
Current portion of notes receivable
    14,824       2,364  
Prepaid insurance and other
    59,563       51,116  
 
           
 
               
Total current assets
    419,787       304,302  
 
           
 
               
Property, plant and equipment, net
    626,558       440,328  
Oil and gas assets, net, under the successful efforts method of accounting
    177,670       94,634  
Goodwill
    444,687       220,064  
Notes receivable
    16,137       29,483  
Equity-method investments
    64,603       953  
Intangible and other long-term assets, net
    125,036       7,486  
 
           
 
               
Total assets
  $ 1,874,478     $ 1,097,250  
 
           
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
 
               
Current liabilities:
               
Accounts payable
  $ 65,451     $ 42,035  
Accrued expenses
    141,684       69,926  
Income taxes payable
          11,353  
Fair value of commodity derivative instruments
          10,792  
Current portion of decommissioning liabilities
    35,150       14,268  
Current maturities of long-term debt
    810       810  
 
           
 
               
Total current liabilities
    243,095       149,184  
 
           
 
               
Deferred income taxes
    112,011       91,899  
Decommissioning liabilities
    87,046       107,641  
Long-term debt
    711,505       216,596  
Other long-term liabilities
    10,133       7,556  
Stockholders’ equity:
               
Preferred stock of $0.01 par value. Authorized, 5,000,000 shares; none issued
           
Common stock of $0.001 par value. Authorized, 125,000,000 shares; issued and outstanding 80,617,337 and 79,499,927 shares at December 31, 2006 and 2005, respectively
    81       79  
Additional paid in capital
    411,374       428,507  
Accumulated other comprehensive income (loss), net
    10,288       (4,916 )
Retained earnings
    288,945       100,704  
 
           
 
               
Total stockholders’ equity
    710,688       524,374  
 
           
 
               
Total liabilities and stockholders’ equity
  $ 1,874,478     $ 1,097,250  
 
           
See accompanying notes to consolidated financial statements.

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Operations
Years Ended December 31, 2006, 2005 and 2004
(in thousands, except per share data)
                         
    2006     2005     2004  
Oilfield service and rental revenues
  $ 966,139     $ 656,423     $ 527,331  
Oil and gas revenues
    127,682       78,911       37,008  
 
                 
Total revenues
    1,093,821       735,334       564,339  
 
                 
Cost of oilfield services and rentals
    427,477       330,200       288,561  
Cost of oil and gas sales
    70,028       45,804       21,547  
 
                 
Total cost of services, rentals and sales
    497,505       376,004       310,108  
 
                 
Depreciation, depletion, amortization and accretion
    111,011       89,288       67,337  
General and administrative expenses
    168,416       140,989       110,605  
Reduction in value of assets
          6,994        
Gain on sale of liftboats
          3,544        
 
                 
Income from operations
    316,889       125,603       76,289  
 
                 
Other income (expense):
                       
Interest expense, net of amounts capitalized
    (22,950 )     (21,862 )     (22,476 )
Interest income
    4,612       2,201       1,766  
Loss on early extinguishment of debt
    (12,596 )            
Earnings from equity-method investments
    5,891       1,339       1,329  
Reduction in value of equity-method investment
          (1,250 )      
 
                 
Income before income taxes
    291,846       106,031       56,908  
Income taxes
    103,605       38,172       21,056  
 
                 
Net income
  $ 188,241     $ 67,859     $ 35,852  
 
                 
Basic earnings per share
  $ 2.36     $ 0.87     $ 0.48  
 
                 
Diluted earnings per share
  $ 2.32     $ 0.85     $ 0.47  
 
                 
Weighted average common shares used in computing earnings per share:
                       
Basic
    79,801       78,321       74,896  
Incremental common shares from stock options
    1,451       1,394       994  
Incremental common shares from restricted stock units
    37       20       10  
 
                 
Diluted
    81,289       79,735       75,900  
 
                 
See accompanying notes to consolidated financial statements.

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Changes in Stockholders’ Equity
Years Ended December 31, 2006, 2005 and 2004
(in thousands, except share data)
                                                                 
                                            Accumulated     Retained        
    Preferred             Common             Additional     other     earnings        
    stock     Preferred     stock     Common     paid-in     comprehensive     (Accumulated        
    shares     stock     shares     stock     capital     income (loss), net     deficit)     Total  
Balances, December 31, 2003
        $       74,099,081     $ 74     $ 370,798     $ 264     $ (3,007 )   $ 368,129  
Comprehensive income:
                                                               
Net income
                                        35,852       35,852  
Other comprehensive income -
                                                               
Changes in fair value of hedging positions, net of tax
                                  (1,661 )           (1,661 )
Foreign currency translation adjustment
                                  4,281             4,281  
 
                                               
Total comprehensive income
                                  2,620       35,852       38,472  
Stock issued for cash
                11,151,121       12       130,253                   130,265  
Purchase and retirement of stock
                (9,696,627 )     (10 )     (113,428 )                 (113,438 )
Grant of restricted stock units
                            180                   180  
Issuance of shares in exchange for restricted stock units
                9,783                                
Exercise of stock options and directors’ stock compensation
                1,202,945       1       8,295                   8,296  
Tax benefit from stock options
                            1,975                   1,975  
 
                                               
Balances, December 31, 2004
                76,766,303       77       398,073       2,884       32,845       433,879  
Comprehensive income:
                                                               
Net income
                                        67,859       67,859  
Other comprehensive income -
                                                               
Changes in fair value of hedging positions, net of tax
                                  (5,138 )           (2,662 )
Foreign currency translation adjustment
                                  (2,662 )           (5,138 )
 
                                               
Total comprehensive income
                                  (7,800 )     67,859       60,059  
Grant of restricted stock units
                            158                   158  
Grant of restricted stock
                24,000             178                   178  
Exercise of stock options
                2,709,624       2       18,157                   18,159  
Tax benefit from stock options
                            11,941                   11,941  
 
                                               
Balances, December 31, 2005
        $       79,499,927     $ 79     $ 428,507     $ (4,916 )   $ 100,704     $ 524,374  
See accompanying notes to consolidated financial statements.

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Changes in Stockholders’ Equity (Continued)
Years Ended December 31, 2006, 2005 and 2004
(in thousands, except share data)
                                                                 
                                            Accumulated              
    Preferred             Common             Additional     other              
    stock     Preferred     stock     Common     paid-in     comprehensive     Retained        
    shares     stock     shares     stock     capital     income (loss), net     earnings     Total  
Balances, December 31, 2005
        $       79,499,927     $ 79     $ 428,507     $ (4,916 )   $ 100,704     $ 524,374  
Comprehensive income:
                                                               
Net income
                                        188,241       188,241  
Other comprehensive income -
                                                               
Changes in fair value of hedging positions, net of tax
                                  6,799             6,799  
Foreign currency translation adjustment
                                  8,405             8,405  
 
                                               
Total comprehensive income
                                  15,204       188,241       203,445  
Grant of restricted stock units
                            542                   542  
Grant of restricted stock, net of forfeitures
                242,775             986                   986  
Exercise of stock options
                244,047       1       2,802                   2,803  
Tax benefit from stock options
                            1,429                   1,429  
Stock option compensation expense
                            847                   847  
Issuance of common stock in connection with acquisition of Warrior Energy Services Corporation
                5,369,888       5       136,336                   136,341  
Shares repurchased and retired
                (4,739,300 )     (4 )     (159,995 )                 (159,999 )
Purchase of common stock call options related to exchangeable notes, net of tax benefit of $35,520
                            (60,480 )                 (60,480 )
Sale of common stock warrant related to exchangeable notes
                            60,400                   60,400  
 
                                               
Balances, December 31, 2006
        $       80,617,337     $ 81     $ 411,374     $ 10,288     $ 288,945     $ 710,688  
 
                                               
See accompanying notes to consolidated financial statements.

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Years Ended December 31, 2006, 2005 and 2004
(in thousands)
                         
    2006     2005     2004  
Cash flows from operating activities:
                       
Net income
  $ 188,241     $ 67,859     $ 35,852  
Adjustments to reconcile net income to net cash provided by operating activities:
                       
Depreciation, depletion, amortization and accretion
    111,011       89,288       67,337  
Deferred income taxes
    15,663       442       15,234  
Stock-based and performance share unit compensation expense
    6,159       1,404        
Reduction in value of assets and equity-method investment
          8,244        
Earnings from equity-method investments
    (5,891 )     (1,339 )     (1,329 )
Write-off of debt acquisition costs
    2,817              
Amortization of debt acquisition costs and note discount
    1,321       1,127       887  
Gain on sale of liftboats
          (3,544 )      
Changes in operating assets and liabilities, net of acquisitions and dispositions:
                       
Receivables
    (88,298 )     (32,095 )     (35,279 )
Other, net
    13,892       (11,598 )     (9,346 )
Accounts payable
    7,259       5,696       16,142  
Accrued expenses
    43,379       15,530       13,866  
Decommissioning liabilities
    (2,255 )     (8,772 )     (9,157 )
Income taxes
    (13,084 )     26,137       (2,876 )
 
                 
Net cash provided by operating activities
    280,214       158,379       91,331  
 
                 
Cash flows from investing activities:
                       
Payments for capital expenditures
    (242,936 )     (125,166 )     (74,125 )
Acquisitions of businesses, net of cash acquired
    (239,339 )     (6,435 )     (24,361 )
Acquisitions of oil and gas properties, net of cash acquired
    (46,631 )     3,686       (10,676 )
Cash proceeds from sale of subsidiary, net of cash sold
    18,343              
Cash contributed to equity-method investment
    (57,781 )            
Cash proceeds from sale of equity-method investment
          12,489        
Cash proceeds from sale of liftboats, net
          19,588        
Other
    (13,634 )     (1,097 )      
 
                 
Net cash used in investing activities
    (581,978 )     (96,935 )     (109,162 )
 
                 
Cash flows from financing activities:
                       
Proceeds from long-term debt
    695,467              
Principal payments on long-term debt
    (200,810 )     (39,310 )     (13,713 )
Payment of debt acquisition costs
    (18,357 )     (439 )     (60 )
Purchase of common stock call options related to exchangeable notes
    (96,000 )            
Sale of common stock warrants related to exchangeable notes
    60,400              
Proceeds from exercise of stock options
    2,803       18,161       10,271  
Tax benefit from exercise of stock options
    1,429              
Proceeds from issuance of stock
                130,265  
Purchase and retirement of stock
    (159,999 )           (113,438 )
 
                 
Net cash provided by (used in) financing activities
    284,933       (21,588 )     13,325  
 
                 
Effect of exchange rate changes in cash
    1,344       (680 )     (7 )
 
                 
Net increase (decrease) in cash and cash equivalents
    (15,487 )     39,176       (4,513 )
Cash and cash equivalents at beginning of year
    54,457       15,281       19,794  
 
                 
Cash and cash equivalents at end of year
  $ 38,970     $ 54,457     $ 15,281  
 
                 
See accompanying notes to consolidated financial statements.

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2006, 2005 and 2004
(1)   Summary of Significant Accounting Policies
  (a)   Basis of Presentation
 
      The consolidated financial statements include the accounts of Superior Energy Services, Inc. and subsidiaries (the Company). All significant intercompany accounts and transactions are eliminated in consolidation. Certain previously reported amounts have been reclassified to conform to the 2006 presentation.
 
  (b)   Business
 
      The Company is a leading provider of specialized oilfield services and equipment focusing on serving the production-related and drilling-related needs of oil and gas companies. The Company provides most of the services, tools and liftboats necessary to maintain, enhance and extend offshore producing wells, as well as plug and abandonment services at the end of their life cycle.
 
      The Company also acquires oil and gas properties in order to provide additional opportunities for its well intervention operations in the Gulf of Mexico. The Company acquires and produces oil and gas properties, provides various production-related services to the properties and decommissions and abandons the properties.
 
  (c)   Use of Estimates
 
      The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
 
  (d)   Major Customers and Concentration of Credit Risk
 
      A majority of the Company’s business is conducted with major and independent oil and gas exploration companies. The Company evaluates the financial strength of its customers and provides allowances for probable credit losses when deemed necessary but does not require collateral to support the customer receivables.
 
      The market for the Company’s services and products is primarily the offshore and onshore oil and gas industry in the United States and select international market areas. Oil and gas companies make capital expenditures on exploration, drilling and production operations. The level of these expenditures has been characterized by significant volatility.
 
      The Company derives a large amount of revenue from a small number of major and independent oil and gas companies. In 2006 and 2005, Shell accounted for approximately 12% and 10%, respectively, of total revenue, primarily related to our oil and gas and rental tools segments. No customer accounted for more than 10% of the Company’s total revenue in 2004. 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 investments with a maturity of 90 days or less to be cash equivalents.
 
  (f)   Accounts Receivable and Allowances
 
      Trade accounts receivables are recorded at the invoiced amount and do not bear interest. The Company maintains allowances for estimated uncollectible receivables including bad debts and other items. The allowance for doubtful accounts is based on the Company’s best estimate of the amount of probable uncollectible amounts in existing accounts receivable. The Company determines the allowance based on historical write-off experience and specific identification.
 
  (g)   Prepaid Insurance and Other
 
      Prepaid insurance and other includes approximately $13.6 million and $23.9 million in insurance receivables at December 31, 2006 and 2005, respectively. The December 31, 2006 and 2005 balances are primarily due to the impact of Hurricanes Katrina and Rita on our oil and gas properties, as well as our equipment. The insurance deductibles on Hurricanes Katrina and Rita of approximately $1 million were expensed during 2005. All amounts not expected to be reimbursed by insurance are expensed as incurred.
 
  (h)   Property, Plant and Equipment
 
      Property, plant and equipment are stated at cost, except for assets acquired using purchase accounting, which are recorded at fair value as of the date of acquisition. With the exception of the Company’s liftboats, derrick barge and oil and gas assets, depreciation is computed using the straight-line method over the estimated useful lives of the related assets as follows:
     
Buildings and improvements
  5 to 40 years
Marine vessels and equipment
  5 to 25 years
Machinery and equipment
  5 to 20 years
Automobiles, trucks, tractors and trailers
  2 to 10 years
Furniture and fixtures
  3 to 10 years
The Company’s liftboats and derrick barge are depreciated using the units-of-production method based on the utilization of the vessels and are subject to a minimum amount of annual depreciation. The Company’s oil and gas producing assets are depleted using the units-of-production method based on applicable quantities of oil and gas produced. The units-of-production method is used for these assets because depreciation and depletion occur primarily through use rather than through the passage of time.
The Company capitalizes interest on the cost of major capital projects during the active construction period. Capitalized interest is added to the cost of the underlying assets and is amortized over the useful lives of the assets. For 2006 and 2005, the Company capitalized approximately $924,000 and $456,000, respectively, of interest for various capital projects. There was no interest capitalized during 2004.
Long-lived assets and certain identifiable intangibles are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the assets. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value. Assets are grouped by subsidiary or division for the impairment testing, except for liftboats which are grouped together by size. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell.

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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.
Oil and gas properties are assessed for impairment in value on a field-by-field basis whenever impairment indicators become evident. The Company uses its current estimate of future revenues and operating expenses to test the capitalized costs for impairment. In the event net undiscounted cash flows are less than the carrying value, an impairment loss is recorded based on the present value of expected future net cash flows over the economic lives of the reserves.
  (i)   Goodwill
 
      The Company accounts for goodwill and other intangible assets in accordance with Statement of Financial Accounting Standards No. 142 (FAS No. 142), “Goodwill and Other Intangible Assets.” FAS No. 142 requires that goodwill as well as other intangible assets with indefinite lives no longer be amortized, but instead tested annually for impairment. To test for impairment, the Company identifies its reporting units (which are consistent with the 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. No impairment loss was recognized in the years ended December 31, 2006, 2005 or 2004 under this method. However, in 2005 the Company reduced the value of goodwill by approximately $3.8 million to approximate the sales price of its environmental subsidiary, which was sold in 2006 (see notes 4 and 11). Goodwill increased by approximately $224.2 million in 2006 as a result of the Company’s business acquisitions including the acquisition of Warrior Energy Services Corporation. Goodwill increased in 2006 by approximately $3.2 million as the result of changes in foreign currency exchange rates and decreased by approximately $2.8 million as the result of the sale of the Company’s environmental subsidiary. Goodwill has been allocated to the Company’s reportable segments as follows: $285.3 million to the well intervention segment; $148.2 million to the rental tools segment; and $11.2 million to the marine segment.
 
  (j)   Notes Receivable
 
      Notes receivable consist of commitments from the sellers of oil and gas properties towards the abandonment of the acquired properties. Pursuant to the agreement with the sellers, the Company will invoice the sellers agreed upon amounts at the completion of certain decommissioning activities. These receivables are recorded at present value, and the related discounts are amortized to interest income, based on the expected timing of the decommissioning activities.
 
  (k)   Intangible and Other Long-Term Assets
 
      Intangible and other long-term assets consist of the following at December 31, 2006 and 2005 (amounts in thousands):

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    December 31, 2006     December 31, 2005  
    Gross     Accumulated     Net     Gross     Accumulated     Net  
    Amount     Amortization     Balance     Amount     Amortization     Balance  
Customer relationships
  $ 88,360     $ (451 )   $ 87,909     $ 160     $ (98 )   $ 62  
Tradenames
    12,788       (116 )     12,672       88       (57 )     31  
Non-compete agreements
    500       (70 )     430                    
Debt acquisition costs
    19,736       (301 )     19,435       9,623       (4,643 )     4,980  
Deferred compensation plan assets
    4,265             4,265       1,410             1,410  
Other
    444       (119 )     325       1,772       (769 )     1,003  
 
                                   
Total
  $ 126,093     $ (1,057 )   $ 125,036     $ 13,053     $ (5,567 )   $ 7,486  
 
                                   
Customer relationships, tradenames, and non-compete agreements are amortized using the straight-line method over their estimated useful lives of 15 years, 20 years, and 2 years, respectively. Debt acquisition costs are amortized primarily using the effective interest method over the life of the related debt agreements ranging from 5 to 25 years. Amortization expense was approximately $0.6 million. $0.3 million and $0.3 million for the years ended December 31, 2006, 2005 and 2004, respectively. Estimated annual amortization will be approximately $7 million for each of the next five years, excluding the effects of any acquisitions or disposition subsequent to December 31, 2006.
  (l)   Decommissioning Liability
 
      The Company records estimated future decommissioning liabilities related to its oil and gas producing properties pursuant to the provisions of Statement of Financial Accounting Standards No. 143 (FAS No. 143), “Accounting for Asset Retirement Obligations.” FAS No. 143 requires entities to record the fair value of a liability at estimated present value for an asset retirement obligation (decommissioning liabilities) in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. Subsequent to initial measurement, the decommissioning liability is required to be accreted each period to present value. The 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 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 incurred costs, then the difference is reported as income (or loss) within revenue during the period in which the work is performed. The Company reviews the adequacy of its decommissioning liability whenever indicators suggest that the estimated cash flows needed to satisfy the liability have changed materially. The timing and amounts of these cash flows are estimates, and changes to these estimates may result in additional (or decreased) liabilities recorded, which in turn would increase (or decrease) the carrying values of the related oil and gas properties.
 
      The following table summarizes the activity for the Company’s decommissioning liability for the twelve months ended December 31, 2006, 2005 and 2004 (amounts in thousands):

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    Year Ended December 31,  
    2006     2005  
Decommissioning liabilities, at beginning of period
  $ 121,909     $ 114,018  
Liabilities acquired and incurred
    3,554       11,494  
Liabilities settled
    (2,255 )     (8,772 )
Accretion
    4,866       4,476  
Revision in estimated liabilities
    (5,878 )     693  
 
           
Total
    122,196       121,909  
Current portion of decommissioning liabilities
    35,150       14,268  
 
           
Decommissioning liabilities, at end of period
  $ 87,046     $ 107,641  
 
           
  (m)   Revenue Recognition
 
      Revenue is recognized when services or equipment are provided. The Company contracts for marine, well intervention and environmental projects either on a day rate or turnkey basis, with a majority of its projects conducted on a day rate basis. The Company’s rental tools are rented on a day rate basis, and revenue from the sale of equipment is recognized when the equipment is shipped. Reimbursements from customers for the cost of rental tools that are damaged or lost down-hole are reflected as revenue at the time of the incident. The Company recognizes oil and gas revenue from its interests in producing wells as oil and natural gas is sold from those wells. The Company is accounting for the revenues and related costs on its contract to construct a derrick barge for a third party on the percentage-of-completion method utilizing engineering estimates and construction progress (see note 7).
 
  (n)   Income Taxes
 
      The Company provides for income taxes in accordance with Statement of Financial Accounting Standards No. 109 (FAS No. 109), “Accounting for Income Taxes.” FAS No. 109 requires an asset and liability approach for financial accounting and reporting for income taxes. Deferred income taxes reflect the impact of temporary differences between amounts of assets and liabilities for financial reporting purposes and such amounts as measured by tax laws.
 
  (o)   Earnings per Share
 
      Basic earnings per share is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share is computed in the same manner as basic earnings per share except that the denominator is increased to include the number of additional common shares that could have been outstanding assuming the exercise of stock options and restricted stock units and the potential shares that would have a dilutive effect on earnings per share.
 
  (p)   Financial Instruments
 
      The fair value of the Company’s financial instruments of cash equivalents, 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 $711.6 million at December 31, 2006.
 
  (q)   Foreign Currency
 
      The functional currency for the Company’s United Kingdom subsidiary is the British pound, and its financial statements are measured in British pounds. The assets and liabilities are translated to U.S. dollars at currency exchange rates as of the balance sheet date, and the revenues and expenses are translated at the average currency exchange rates for the period. The aggregate effect of translation

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      adjustments are reported as accumulated other comprehensive income (loss) in the Company’s stockholders’ equity.
 
      The functional currency for the Company’s other foreign subsidiaries is the U.S. dollar. The financial statements of these subsidiaries are remeasured into U.S. dollars using the historical exchange rate for most of the long-term assets and liabilities and the balance sheet date exchange rate for most of the current assets and liabilities. An average exchange rate is used for each period for revenues and expenses. These transaction gains and losses, as well as any other transactions in a currency other than the functional currency, are included in general and administrative expenses in the consolidated statements of operations in the period in which the currency exchange rates change. The Company recorded approximately $0.8 million, $(0.2) million and $0.4 million of these transaction (gains) losses included in general and administrative expenses in the years ended December 31, 2006, 2005 and 2004, respectively.
 
  (r)   Stock Based Compensation
 
      Effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123(R) (FAS No. 123R), “Share-Based Payment (as amended)” which requires that compensation costs relating to share-based payment transactions be recognized in the financial statements. The cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the employee’s requisite service period (generally the vesting period of the equity award). The Company is using the modified prospective application method and, accordingly, financial statement amounts for prior periods presented in these financial statements have not been restated to reflect the fair value method of recognizing compensation costs relating to non-qualified stock options. See note 3 regarding the Company’s adoption of FAS No. 123(R).
 
      Prior to January 1, 2006, the Company followed the disclosure-only provisions of Statement of Financial Accounting Standards No. 123 (FAS No. 123), “Accounting for Stock-Based Compensation” using the measurement principles prescribed in Accounting Principles Board’s Opinion No. 25, “Accounting for Stock Issued to Employees.” No stock-based compensation costs were recognized for stock options in net income prior to January 1, 2006, as all options granted had an exercise price equal to the market value of the underlying common stock on the date of the grant. Stock compensation costs from the grant of restricted stock and restricted stock units were expensed as incurred.
 
  (s)   Hedging Activities
 
      The Company entered into hedging transactions in 2004 that expired on August 31, 2006 to secure a commodity price for a portion of its oil production and reduce its exposure to oil price fluctuations. The Company does not enter into derivative transactions for trading purposes. The Company used financially-settled crude oil swaps and zero-cost collars that provided floor and ceiling prices with varying upside price participation. The Company’s swaps and zero-cost collars were designated and accounted for as cash flow hedges. The Company has not hedged any of its natural gas production. The Company recognized the fair value of all derivative instruments as assets or liabilities on the balance sheet. Changes in the fair value of cash flow hedges, to the extent the hedge was effective, were recognized in other comprehensive income until the hedged item was settled and recorded in oil and gas revenues. For the years ended December 31, 2006, 2005 and 2004, hedging settlement payments reduced oil and gas revenues by approximately $13.8 million, $10.2 million and $1.6 million, respectively. The Company did not record any material gains or losses due to hedge ineffectiveness for these periods.
 
  (t)   Other Comprehensive Income (Loss)
 
      The following table reconciles the change in accumulated other comprehensive income (loss) for the years ended December 31, 2006 and 2005 (amounts in thousands):

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    Year Ended December 31,  
    2006     2005  
Accumulated other comprehensive (loss) income, net, December 31, 2005 and 2004, respectively
  $ (4,916 )   $ 2,884  
 
               
Other comprehensive income (loss), net of tax:
               
Hedging activities:
               
Reclassification adjustment for settled contracts, net of tax of $5,124 in 2006 and $3,656 in 2005
    8,726       6,499  
Changes in fair value of outstanding hedging positions, net of tax of ($1,131) in 2006 and ($6,545) in 2005
    (1,927 )     (11,637 )
Foreign currency translation adjustment
    8,405       (2,662 )
 
           
 
               
Total other comprehensive income (loss)
    15,204       (7,800 )
 
           
 
               
Accumulated other comprehensive income (loss), net, December 31, 2006 and 2005, respectively
  $ 10,288     $ (4,916 )
 
           
(2)   Supplemental Cash Flow Information
The following table includes the Company’s supplemental cash flow information for the years ended December 31, 2006, 2005 and 2004 (amounts in thousands):
                         
    2006     2005     2004  
Cash paid for interest
  $ 32,295     $ 21,152     $ 23,320  
 
                 
Cash paid for income taxes
  $ 100,431     $ 10,789     $ 7,360  
 
                 
 
                       
Details of business acquisitions:
                       
Fair value of assets
  $ 460,771     $ 6,627     $ 25,614  
Fair value of liabilities
    (76,887 )     (31 )     (1,158 )
Common stock issued
    (136,341 )            
 
                 
Cash paid
    247,543       6,596       24,456  
Less cash acquired
    (8,204 )     (163 )     (95 )
 
                 
Net cash paid for acquisitions
  $ 239,339     $ 6,433     $ 24,361  
 
                 
 
                       
Details of oil and gas property acquisitions:
                       
Fair value of assets
  $ 50,350     $ 11,494     $ 97,792  
Fair value of liabilities
    (3,719 )     (11,494 )     (82,107 )
 
                 
Cash paid
    46,631             15,685  
Less cash acquired
          (3,686 )     (5,009 )
 
                 
Net cash paid for acquisitions
  $ 46,631     $ (3,686 )   $ 10,676  
 
                 
 
                       
Non-cash investing activity:
                       
Receivable from sale of affiliate
  $     $ 1,305     $  
 
                 
 
                       
Additional consideration payable on acquisitions
  $     $     $ 5,272  
 
                 
 
                       
Non-cash financing activity:
                       
Deferred tax asset on purchase of common stock call options related to exchangeable notes
  $ 35,520     $     $  
 
                 

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(3) Stock-Based and Long-Term Compensation
The Company maintains the 2005 Stock Incentive Plan, the 2002 Stock Incentive Plan, the 1999 Stock Incentive Plan and the 1995 Stock Incentive Plan, as amended. These plans provide long-term incentives to the Company’s key employees, including officers and directors, consultants and advisers (Eligible Participants). Under the 2005 Stock Incentive Plan, the 2002 Stock Incentive Plan, the 1999 Stock Incentive Plan and the 1995 Stock Incentive Plan, the Company may grant incentive stock options, non-qualified stock options, restricted stock, restricted stock units, stock appreciation rights, other stock-based awards or any combination thereof to Eligible Participants for up to 4,000,000 shares, 1,400,000 shares, 5,929,327 shares and 1,900,000 shares, respectively, of the 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 plans, provided the exercise price may not be less than the fair value of the common share on the date of grant. All of the options which have been granted under the 1995 Stock Incentive Plan, the 1999 Stock Incentive Plan and the 2002 Stock Incentive Plan were fully-vested by December 31, 2006.
Stock Options
The Company has granted non-qualified stock options under its stock incentive plans. The options generally vest in equal installments over three years and expire in ten years. Non-vested options are generally forfeited upon termination of employment. On February 23, 2006, the Company granted 212,600 non-qualified stock options and on December 14, 2006, the Company granted 127,617 non-qualified stock options from its 2005 Stock Incentive Plan under these same terms.
Beginning January 1, 2006, the Company adopted FAS No. 123R and began recognizing compensation expense for stock option grants based on the fair value at the date of grant using the Black-Scholes-Merton option pricing model. With the adoption of FAS No. 123R, the Company has contracted a third party to assist in the valuation of option grants. The Company uses historical data, among other factors, to estimate the expected price volatility, the expected option life and the expected forfeiture rate. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant for the expected life of the option. The following table presents the fair value of stock option grants made during the years ended December 31, 2006, 2005 and 2004 and the related assumptions used to calculate the fair value:
                         
    Years Ended December 31,  
    2006     2005     2004  
    Actual     Pro Forma     Pro Forma  
Weighted-average fair value of grants
  $ 13.02     $ 7.47     $ 6.22  
 
                 
 
                       
Black-Scholes-Merton Assumptions:
                       
Risk free interest rate
    4.57 %     3.85 %     4.28 %
Expected life (years)
    5       6       5  
Volatility
    44.36 %     38.91 %     65.22 %
Dividend yield
                 
The Company’s compensation expense related to stock options for the year ended December 31, 2006 was approximately $0.8 million, which is reflected in general and administrative expenses. No compensation expense related to options was recorded during the years ended December 31, 2005 or 2004.
The pro forma data presented below show the effects of stock option costs had they been expensed in prior periods (amounts are in thousands, except per share amounts):

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    2005     2004  
Net income, as reported
  $ 67,859     $ 35,852  
Stock-based employee compensation expense, net of tax
    (4,421 )     (6,999 )
 
           
 
               
Pro forma net income
  $ 63,438     $ 28,853  
 
           
 
               
Basic earnings per share:
               
Earnings, as reported
  $ 0.87     $ 0.48  
Stock-based employee compensation expense, net of tax
    (0.06 )     (0.09 )
 
           
 
               
Pro forma earnings per share
  $ 0.81     $ 0.39  
 
           
 
               
Diluted earnings per share:
               
Earnings, as reported
  $ 0.85     $ 0.47  
Stock-based employee compensation expense, net of tax
    (0.06 )     (0.09 )
 
           
 
               
Pro forma earnings per share
  $ 0.79     $ 0.38  
 
           
The following table summarizes stock option activity for the years ended December 31, 2006, 2005 and 2004:
                                 
                    Weighted        
            Weighted     Average     Aggregate  
            Average     Remaining     Intrinsic  
    Number of     Option     Contractual     Value (in  
    Options     Price     Term (in years)     thousands)  
Outstanding at December 31, 2003
    5,628,000     $ 7.53                  
 
                               
Granted
    1,490,000     $ 10.66                  
Exercised
    (1,196,060 )   $ 7.01                  
Forfeited
    (124,645 )   $ 8.14                  
 
                             
 
                               
Outstanding at December 31, 2004
    5,797,295     $ 8.43                  
 
                               
Granted
    863,500     $ 17.46                  
Exercised
    (2,709,624 )   $ 6.94                  
Forfeited
    (57,538 )   $ 10.23                  
 
                             
 
                               
Outstanding at December 31, 2005
    3,893,633     $ 11.44                  
 
                               
Granted
    340,217     $ 29.00                  
Exercised
    (244,047 )   $ 11.48                  
Forfeited
    (18,917 )   $ 16.85                  
 
                             
 
                               
Outstanding at December 31, 2006
    3,970,886     $ 12.91       6.9     $ 78,880  
 
                       
 
                               
Exercisable at December 31, 2006
    3,630,669     $ 11.40       6.7     $ 77,246  
 
                       
 
                               
Options expected to vest
    340,217     $ 13.02       9.5     $ 1,635  
 
                       
The aggregate intrinsic value in the table above represents the total pre-tax intrinsic value (the difference between the Company’s closing stock price on December 31, 2006 and the option price, multiplied by the number of “in-the-money” options) that would have been received by the option holders if all the options had been exercised on

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December 31, 2006. The Company expects all of its remaining non-vested options to vest as they are primarily held by its officers and senior managers.
The total intrinsic value of options exercised during the year ended December 31, 2006 (the difference between the stock price upon exercise and the option price) was approximately $4.0 million. The Company received approximately $2.8 million during the year ended December 31, 2006 from employee stock option exercises. In accordance with FAS No. 123R, the Company has reported the tax benefits of approximately $1.4 million from the exercise of stock options for the year ended December 31, 2006 as financing cash flows. Prior to implementation of FAS No. 123R, the Company reported the tax benefits from the exercise of stock options of approximately $11.9 million in operating cash flows for the year ended December 31, 2005.
A summary of information regarding stock options outstanding at December 31, 2006 is as follows:
                                         
    Options Outstanding   Options Exercisable
Range of           Weighted Average   Weighted           Weighted
Exercise           Remaining   Average           Average
Prices   Shares   Contractual Life   Price   Shares   Price
 
$  4.75 - $  5.75
    24,500     2.1 years   $ 5.57       24,500     $ 5.57  
$  7.31 - $  8.79
    678,797     5.0 years   $ 8.37       678,797     $ 8.37  
$  9.10 - $  9.90
    716,372     4.9 years   $ 9.40       716,372     $ 9.40  
$10.36 - $10.90
    1,430,000     7.6 years   $ 10.66       1,430,000     $ 10.66  
$12.45 - $17.46
    781,000     8.4 years   $ 17.43       781,000     $ 17.43  
$24.90 - $25.00
    212,600     9.1 years   $ 24.99           $  
$35.60 - $35.70
    127,617     10.0 years   $ 35.69           $  
The following table summarizes non-vested stock option activity for the year ended December 31, 2006:
                 
            Weighted  
            Average  
    Number of     Grant-Date  
    Options     Fair Value  
Non-vested at December 31, 2005
    133,912     $ 3.63  
Granted
    340,217     $ 13.02  
Vested
    (133,245 )   $ 3.64  
Forfeited
    (667 )   $ 3.62  
 
             
 
               
Non-vested at December 31, 2006
    340,217     $ 13.02  
 
           
As of December 31, 2006, there was approximately $3.7 million of unrecognized compensation expense related to non-vested stock options outstanding. The Company expects to recognize approximately $1.4 million, $1.5 million and $0.8 million of compensation expense during the years 2007, 2008 and 2009, respectively, for these non-vested stock options outstanding.
Restricted Stock
During the year ended December 31, 2006, the Company granted 247,975 shares of restricted stock to its employees. These shares of restricted stock vest in equal annual installments over three years. Non-vested shares are generally forfeited upon the termination of employment. Holders of the shares of restricted stock are entitled to all rights of a shareholder of the Company with respect to the restricted stock, including the right to vote the shares and receive all dividends and other distributions declared thereon. Compensation expense associated with shares of restricted stock is measured based on the grant-date fair value of our common stock and is recognized on a straight-line basis over the vesting period. The Company’s compensation expense related to shares of restricted stock outstanding for the

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years ended December 31, 2006 and 2005 was approximately $1.0 million and $0.2 million, respectively, which is reflected in general and administrative expenses.
A summary of the status of the shares of restricted stock for the year ended December 31, 2006 is presented in the table below:
                 
            Weighted  
    Number of     Average Grant  
    Shares     Date Fair Value  
Non-vested at December 31, 2005
    24,000     $ 22.24  
Granted
    247,975     $ 31.19  
Vested
    (9,000 )   $ 22.55  
Forfeited
    (5,200 )   $ 24.99  
 
             
 
               
Non-vested at December 31, 2006
    257,775     $ 30.78  
 
           
As of December 31, 2006, there was approximately $7.0 million of unrecognized compensation expense related to non-vested restricted stock shares. The Company expects to recognize approximately $2.6 million, $2.5 million and $1.8 million during the years 2007, 2008 and 2009, respectively, for these shares of non-vested restricted stock.
Restricted Stock Units
In May 2006, the Company’s stockholders approved the Amended and Restated 2004 Directors Restricted Stock Units Plan. The plan provides that each non-employee director is granted a number of restricted stock units having an aggregate value of $100,000, with the exact number of units determined by dividing $100,000 by the fair market value of the Company’s common stock on the day of the annual stockholders’ meeting or a pro rata amount if the appointment occurs subsequent to the annual stockholders’ meeting. A restricted stock unit represents the right to receive from the Company, within 30 days of the date the participant ceases to serve on the Board, one share of the Company’s common stock. As a result of this plan, 37,482 restricted stock units were outstanding at December 31, 2006. The Company’s expense related to restricted stock units for the year ended December 31, 2006 and 2005 was approximately $0.9 million and $0.2 million, respectively, which is reflected in general and administrative expenses.
A summary of the activity of restricted stock units for the year ended December 31, 2006 is presented in the table below:
                 
    Number of     Weighted  
    Restricted     Average Grant  
    Stock Units     Date Fair Value  
Outstanding at December 31, 2005
    19,998     $ 12.38  
Granted
    17,484     $ 30.98  
 
             
 
               
Outstanding at December 31, 2006
    37,482     $ 21.06  
 
           
Performance Share Units
The Company awards performance share units (PSUs) to its employees as part of the Company’s long-term incentive program. There is a three-year performance period associated with each PSU grant date. The two performance measures applicable to all participants are the Company’s return on invested capital and total shareholder return relative to those of the Company’s pre-defined “peer group.” The PSUs provide for settlement in cash or up to 50% in equivalent value in the Company’s common stock, if the participant has met specified continued service requirements. At December 31, 2006, there were 119,179 PSUs outstanding (31,128, 32,669 and 55,382 related to the three-year performance periods ending December 31, 2007, 2008 and 2009, respectively). The

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Company’s compensation expense related to all outstanding PSUs for the years ended December 31, 2006 and 2005 was approximately $3.5 million and $1.0 million, respectively, which is reflected in general and administrative expenses. At December 31, 2006, the Company has recorded a liability of approximately $4.5 million for all outstanding PSUs which is reflected in accrued expenses.
(4) Acquisitions and Dispositions
On December 12, 2006, the Company acquired Warrior Energy Services Corporation (Warrior) for a total purchase price of $374.1 million. The total consideration was comprised of cash payments of $237.8 million (including acquisition costs and repayment of Warrior’s debt) and equity consideration of $136.3 million (5,369,888 shares of common stock valued at $25.39 per share, the average closing market price per share for the five trading day period beginning two trading days before the merger announcement date of September 25, 2006). The acquisition has been accounted for as a purchase, and the results of operations of Warrior have been included from the acquisition date.
Warrior is an oil and gas services company that provides various well intervention services including wireline, electric line, logging, perforating, mechanical services, pipe recovery, plug and abandonment and hydraulic workover services. Warrior also provides various rental tools and equipment to its market areas including drill pipe, handling tools and accessories, pressure control equipment, fishing tools, stabilizers, power swivels, test pumps and hydraulic torque wrenches. Warrior has 25 operating bases in 10 states with operations concentrated in the major onshore and offshore oil and gas producing areas of the United States, including onshore in Alabama, Arkansas, Colorado, Kansas, Louisiana, Mississippi, Montana, New Mexico, North Dakota, Oklahoma, Texas, Utah and Wyoming and offshore in the Gulf of Mexico. The Company acquired Warrior to further strengthen its well intervention and rental operations into these onshore locations.
The assets and liabilities were valued at their estimated fair value as of the date of acquisition. The Company obtained a third party valuation to assist it in the assessment of the fair value of Warrior’s assets and liabilities. The allocation of the purchase price and the valuation of the assets and liabilities will be subject to refinement as the Company gathers additional information with respect to income taxes, outstanding litigation and other items. The Company will have 12 months from the acquisition date to finalize the valuation of the assets and liabilities and any changes to the initial valuation may result in a change to goodwill. The following table summarizes the preliminary estimated fair values of the Warrior assets and liabilities acquired as of the acquisition date (amounts in thousands):
         
ASSETS
       
Current assets
  $ 32,728  
Property, plant and equipment
    98,386  
Goodwill
    218,711  
Intangible and other assets
    101,123  
 
     
 
       
Total assets acquired
  $ 450,948  
 
     
 
       
LIABILITIES
       
Current liabilities
  $ 40,257  
Deferred income taxes
    36,630  
 
     
 
       
Total liabilities assumed
    76,887  
 
     
 
       
Net assets acquired
  $ 374,061  
 
     
The intangible and other assets and the related estimated useful lives include: approximately $88.2 million of customer relationships with a 15 year life, $12.7 million of tradenames with a 20 year life, and $0.2 million of non-compete agreements with a 2 year life. The goodwill was assigned to the well intervention and rental segments of approximately $201.4 million and $17.3 million, respectively.
In July 2006, Coldren Resources LP (Coldren Resources) completed the acquisition from Noble Energy, Inc. (Noble) of substantially all of Noble’s offshore Gulf of Mexico shallow water oil and gas properties. The Company’s wholly-owned subsidiary SPN Resources, LLC (SPN Resources), acquired a 40% interest in Coldren

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Resources for an initial cash investment of $57.8 million. The Company’s investment in Coldren Resources is accounted for under the equity-method of accounting. Amounts included in the pro forma information below represent the Company’s 40% ownership interest in the performance of the Noble properties prior to their acquisition by Coldren Resources in July 2006 and do not include general and administrative expenses associated with these oil and gas properties.
In April 2006, SPN Resources acquired additional oil and gas properties through the acquisition of five offshore Gulf of Mexico leases. Under the terms of the transaction, the Company acquired the properties and assumed the related decommissioning liabilities. The Company paid cash in the amount of $46.6 million and preliminarily recorded decommissioning liabilities of approximately $3.7 million and oil and gas producing assets of approximately $50.3 million.
The Company made other business acquisitions, which were not significant on an individual basis, requiring aggregate cash consideration of $9.8 million in 2006 and $1.3 million in 2005. The Company sold its environmental subsidiary in the first quarter of 2006 for approximately $18.7 million in cash. Also, the Company acquired offshore Gulf of Mexico oil and gas properties and assumed the related decommissioning liabilities in July 2005 for $3.7 million in cash received and the seller’s agreement to pay amounts as decommissioning activities are completed.
The following unaudited pro forma information for the years ended December 31, 2006 and 2005 presents a summary of the consolidated results of operations as if the business acquisitions and disposition described above had occurred on January 1, 2005, with pro forma adjustments to give effect to depreciation, depletion, and certain other adjustments, together with related income tax effects (in thousands, except per share amounts):
                 
    Years Ended December 31,  
    2006     2005  
Revenues
  $ 1,221,259     $ 830,793  
 
           
Net income
  $ 206,286     $ 116,858  
 
           
Basic earnings per share
  $ 2.57     $ 1.48  
 
           
Diluted earnings per share
  $ 2.52     $ 1.45  
 
           
The above pro forma information is not necessarily indicative of the results of operations that would have been achieved had the acquisitions and disposition been effected on January 1, 2005.
Several of the Company’s prior business acquisitions require future payments if specific conditions are met. As of December 31, 2006, the maximum additional consideration payable was approximately $2.4 million, and will be determined and payable through 2008.
Subsequent Event
In January 2007, the Company acquired Duffy & McGovern Accommodations Services Limited (Duffy & McGovern) for approximately $47 million in cash consideration. Duffy & McGovern is a provider of offshore accommodation rentals operating in most major deep water oil and gas territories with major operations in Europe, Africa, the Americas and South East Asia. Duffy & McGovern has a current working fleet of approximately 260 offshore accommodation units, which are certified for deep water projects. The Company acquired Duffy & McGovern to further expand its rental tools segment internationally. The acquisition will be accounted for as a purchase.
(5) Property, Plant and Equipment
A summary of property, plant and equipment at December 31, 2006 and 2005 (in thousands) is as follows:

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    2006     2005  
Buildings and improvements and leasehold improvements
  $ 53,240     $ 58,567  
Marine vessels and equipment
    217,422       177,047  
Machinery and equipment
    561,570       394,582  
Automobiles, trucks, tractors and trailers
    23,829       9,428  
Furniture and fixtures
    17,274       13,440  
Construction-in-progress
    48,274       19,054  
Land
    7,328       6,581  
 
           
 
               
 
    928,937       678,699  
Accumulated depreciation
    (302,379 )     (238,371 )
 
           
 
               
Property, plant and equipment, net
  $ 626,558     $ 440,328  
 
           
 
               
Oil and gas assets
    229,329       119,986  
Accumulated depletion
    (51,659 )     (25,352 )
 
           
Oil and gas assets, net, under the successful efforts method of accounting
  $ 177,670     $ 94,634  
 
           
The Company has approximately $11 million and $16 million of leasehold improvements at December 31, 2006 and 2005, respectively. These leasehold improvements are depreciated over the shorter of the life of the asset or the life of the lease using the straight-line method. Depreciation expense (excluding depletion, amortization and accretion) was approximately $79.3 million, $68.6 million and $57.1 million for the years ended December 31, 2006, 2005 and 2004, respectively.
(6) Equity-Method Investments
Investments in entities that are not controlled by the Company, but where the Company has the ability to exercise influence over the operations are accounted for using the equity-method. The Company’s share of the income or losses of these entities is reflected as earnings from equity-method investments on its Consolidated Statements of Operations.
In May 2006, SPN Resources acquired a 40% interest in Coldren Resources. In July 2006, Coldren Resources completed its acquisition of the oil and gas properties from Noble. The Company made total cash contributions for its equity-method investment of approximately $57.8 million through December 31, 2006. The Company’s equity-method investment balance in Coldren Resources is approximately $63.6 million at December 31, 2006, and the earnings from the equity-method investment in Coldren Resources is approximately $5.8 million for the year ended December 31, 2006. Coldren Resources had total proved reserves of approximately 4,940 Mbbls of oil and 88,837 Mmcf of gas at December 31, 2006. Coldren Resources’ standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves is approximately $370.9 million at December 31, 2006.
The Company provides operating and administrative support services to Coldren Resources and receives reimbursement for general and administrative and direct expenses incurred on behalf of Coldren Resources. The Company also, where possible and at competitive rates, provides its products and services to assist Coldren Resources in producing and developing its oil and gas properties. At December 31, 2006, the Company had receivables of approximately $3.0 million due from Coldren Resources. The Company reduced its general and administrative expenses by approximately $1.7 million by the reimbursements due from Coldren Resources. The Company also recorded revenue of approximately $1.4 million from Coldren Resources in 2006. The Company reduces its revenue and its investment in Coldren Resources for its 40% ownership when products and services are provided to and capitalized by Coldren Resources. The Company records these amounts in revenue as Coldren Resources records the related depreciation and depletion expenses. The Company recorded a net reduction to revenue and its investment in Coldren Resources of approximately $23,000 for the year ended December 31, 2006 as a result of these adjustments.

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Summarized balance sheet and statement of operations information for Coldren Resources is as follows (amounts in thousands):
Balance Sheet
         
    December 31,  
    2006  
Current assets
  $ 176,860  
Property, plant and equipment, net
    522,941  
Other long-term assets
    23,135  
 
     
 
       
Total assets
  $ 722,936  
 
     
 
       
Current liabilities
  $ 27,922  
Decommissioning and other long-term liabilities
    89,610  
Long-term debt
    432,697  
 
     
 
       
Total liabilities
    550,229  
 
     
 
       
Accumulated other comprehensive income, net
    13,861  
Partners’ capital
    158,846  
 
     
 
       
Total capital
    172,707  
 
     
 
       
Total liabilities and partners’ capital
  $ 722,936  
 
     
Statement of Operations
         
    Year Ended  
    December 31,  
    2006  
Revenues
  $ 118,650  
Lease operating expenses
    (30,176 )
Depreciation, depletion, amortization and accretion
    (62,981 )
General and administrative expenses
    (6,535 )
Interest expense
    (21,391 )
Interest income
    1,785  
Gain on derivatives
    15,321  
 
     
 
       
Net income
  $ 14,673  
 
     
Also included in equity-method investments at December 31, 2006 and 2005 is approximately a $1.0 million investment for a 50% ownership in a company that owns an airplane. Earnings from this equity-method investment were approximately $23,000, $9,000 and $264,000 for the years ended December 31, 2006, 2005 and 2004, respectively. The Company recorded approximately $227,000, $195,000 and $178,000 in expense to lease the airplane from this company for the years ended December 31, 2006, 2005 and 2004, respectively.
In November 2005, the Company sold its equity-method investment in a rental tool company. The Company received $12.5 million in cash as a result of the sale and has receivables of approximately $1.1 million at December 31, 2006 for the remaining proceeds to be distributed, of which $0.9 million were received in January 2007. The Company reduced the value of this investment by approximately $1.3 million during 2005 in anticipation of this sale.

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(7) Construction Contract
In July 2006, the Company contracted to construct a derrick barge that will be sold to a third party for approximately $54 million. The contract to construct the derrick barge to the customer’s specifications is accounted for on the percentage-of-completion method utilizing engineering estimates and construction progress. This methodology requires the Company to make estimates regarding the progress against the project schedule and estimated completion date, both of which impact the amount of revenue and gross margin the Company recognizes in each reporting period. Contract costs primarily include sub-contract and program management costs. Provisions for any anticipated losses will be recorded in full when such losses become evident. Included in accrued expenses at December 31, 2006 is approximately $12.3 million of billings in excess of costs and estimated earnings related to this contract.
(8) Long-Term Debt
The Company’s long-term debt as of December 31, 2006 and 2005 consisted of the following (in thousands):
                 
    2006     2005  
Senior Notes — interest payable semiannually at 6.875%, due June 2014
  $ 300,000     $  
Discount on 6.875% Senior Notes
    (4,281 )        
Senior Notes — interest payable semiannually at 8.875%
          200,000  
Senior Exchangeable Notes — interest payable semiannually at 1.5% until December 2011 and 1.25% thereafter, due December 2026
    400,000        
Revolver — interest payable monthly at floating rate, due in June 2011
           
U.S. Government guaranteed long-term financing — interest payable semianually at 6.45%, due in semiannual installments through June 2027
    16,596       17,406  
 
           
 
    712,315       217,406  
Less current portion
    810       810  
 
           
Long-term debt
  $ 711,505     $ 216,596  
 
           
In December 2006, the Company amended its revolving credit facility to increase it to $250 million from $150 million. Any balance outstanding on the revolving credit facility is due on June 14, 2011. At December 31, 2006, the Company had no borrowings under this revolving credit facility but had letters of credit outstanding of approximately $35.6 million, which reduce the Company’s borrowing capacity under the revolving credit facility. Borrowing under the credit facility bear 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 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. At December 31, 2006, the Company was in compliance with all such covenants.
The Company has $16.6 million outstanding in U. S. Government guaranteed long-term financing under Title XI of the Merchant Marine Act of 1936, which is administered by the Maritime Administration (MARAD) for two 245-foot class liftboats. The debt bears an interest rate of 6.45% per annum and is payable in equal semi-annual installments of $405,000, on every June 3rd and December 3rd through June 3, 2027. The 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. At December 31, 2006, the Company was in compliance with all such covenants. This long-term financing ranks equally with the bank credit facility as both are secured by different collateral.

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In the second quarter of 2006, the Company completed a tender offer for approximately 97.6% of its $200 million outstanding of 8 7/8% unsecured senior notes due 2011. The cash consideration for the tender offer was $1,045.63 per $1,000 in aggregate principal amount of senior notes tendered. In conjunction with the tender offer, the Company also received consents to amend the indenture pursuant to which the senior notes were issued to eliminate from the indenture substantially all of the restrictive covenants and certain events of default. After the tender offer was completed, the Company redeemed the remaining outstanding senior notes in accordance with the indenture at the redemption price of $1,044.38 per $1,000 of the principal amount redeemed. The Company recognized a loss on the early extinguishment of debt of approximately $12.6 million, which included the tender premiums, redemption premiums, fees and expenses and the write-off of the remaining unamortized debt acquisition costs associated with these notes.
In May 2006, the Company issued $300 million of 6 7/8% unsecured senior notes due 2014. The Company used the net proceeds to refinance the 8 7/8% senior notes due 2011 and related tender and redemption premiums, fees and related expenses, and to fund the equity investment in Coldren Resources. The indenture governing the notes requires semi-annual interest payments, on every June 1st and December 1st through the maturity date of June 1, 2014. The indenture contains certain covenants that, among other things, restrict the Company from incurring additional debt, repurchasing capital stock, paying dividends or making other distributions, incurring liens, selling assets or entering into certain mergers or acquisitions. At December 31, 2006, the Company was in compliance with all such covenants.
In December 2006, SESI, L.L.C. (Issuer), a wholly owned subsidiary of the Company, issued $400 million of 1.50% Senior Exchangeable Notes due 2026. The notes bear interest at a rate of 1.50% per annum and decrease to 1.25% per annum on December 15, 2011. Interest on the notes is payable semi-annually in arrears on December 15th and June 15th of each year, beginning June 15, 2007. The notes do not contain any restrictive financial covenants.
The notes are the Issuer’s senior, unsecured obligations, and rank equal in right of payment to all other existing and future senior indebtedness of the Issuer. The notes are guaranteed on a senior, unsecured basis by the Company and the Company’s current domestic subsidiaries that guarantee the Issuer’s outstanding 6 7/8% Senior Notes due 2014. Future subsidiaries that guarantee any indebtedness of the Issuer, the Company or a domestic subsidiary will also guarantee the notes.
Under certain circumstances, holders may exchange the notes for shares of the Company’s common stock. The initial exchange rate is 21.9414 shares of common stock per $1,000 principal amount of notes. This is equal to an initial exchange price of $45.58 per share. The exchange price represents a 35% premium over the closing share price at the date of issuance. The notes may be exchanged under the following circumstances:
    during any fiscal quarter (and only during such fiscal quarter) commencing after March 31, 2007, if the last reported sale price of the Company’s common stock is greater than or equal to 135% of the applicable exchange price of the notes for at least 20 trading days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter;
 
    prior to December 15, 2011, during the five business-day period after any ten consecutive trading-day period (the “measurement period”) in which the trading price of $1,000 principal amount of notes for each trading day in the measurement period was less than 95% of the product of the last reported sale price of the Company’s common stock and the exchange rate on such trading day;
 
    if the notes have been called for redemption;
 
    upon the occurrence of specified corporate transactions; or
 
    at any time beginning on September 15, 2026, and ending at the close of business on the second business day immediately preceding the maturity date.
In connection with the exchangeable note transaction, the Company simultaneously entered into agreements with affiliates of the initial purchasers to purchase call options and sell warrants on its common stock. The Company may exercise the call options it purchased at any time to acquire approximately 8.8 million shares of its common stock at a strike price of $45.58 per share. The owners of the warrants may exercise the warrants to purchase from the Company approximately 8.8 million shares of the Company’s common stock at a price of $59.42 per share, subject to certain anti-dilution and other customary adjustments. The warrants may be settled in cash, in shares or in

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a combination of cash and shares, at the Company’s option. The Company paid $96 million (exclusive of a $35.5 million tax benefit) to acquire the call options and received $60.4 million as a result of the sale of the warrants. The $60.5 million purchase of the call options, net of the related tax benefit, was recorded as a reduction to stockholders’ equity and the sale of the warrants was recorded as an increase to stockholders’ equity in accordance with the guidance in EITF Issue No. 00-19, “Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company’s Own Stock.” Subsequent changes in the fair value of the call options and warrants will not be recognized as long as the instruments remain classified in stockholders’ equity.
Because the Company entered into the call option and warrant transactions in connection with the issuance of the exchangeable notes, there will be no impact on basic or dilutive earnings per share unless the price of the Company’s common stock exceeds the initial exchange price of $45.58 per share. In the event the Company’s common stock exceeds $45.58 per share, for the first $1.00 the price exceeds $45.58, there would be dilution of approximately 188,400 shares and the impact on the calculation of earnings per share will vary depending on when during the quarter the $45.58 per share price is reached. As this share price continues to increase, dilution would continue to occur but at a declining rate. If the call options and warrants settle in the Company’s favor, the Company could be exposed to credit risk related to the other parties to the transactions.
The Company has agreed to file a shelf registration statement covering resales of the notes and common stock issuable upon the exchange of the notes that is required to become effective no later than 180 days after the original date of the issuance of the notes. In the event the shelf registration statement does not become effective as described above, the Issuer has agreed to pay additional interest of 0.25% per annum for the first 90 days after the occurrence of the event and 0.50% per annum thereafter, provided that no additional interest will accrue with respect to any period after the second anniversary of the original issuance of the notes. The Company plans to file a resale registration statement with respect to the exchangeable note transaction in March 2007.
Annual maturities of long-term debt for each of the five fiscal years following December 31, 2006 and thereafter are as follows (in thousands):
         
2007
  $ 810  
2008
    810  
2009
    810  
2010
    810  
2011
    810  
Thereafter
    708,265  
 
     
 
       
Total
  $ 712,315  
 
     
(9) Income Taxes
The components of income tax expense (benefit) for the years ended December 31, 2006, 2005 and 2004 are as follows (in thousands):

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    2006     2005     2004  
Current
                       
Federal
  $ 75,017     $ 30,745     $ 87  
State
    1,373       898       415  
Foreign
    11,552       6,087       5,320  
 
                 
 
                       
 
    87,942       37,730       5,822  
 
                 
 
                       
Deferred
                       
Federal
    16,894       1,895       17,569  
State
    1,444       94       105  
Foreign
    (2,675 )     (1,547 )     (2,440 )
 
                 
 
                       
 
    15,663       442       15,234  
 
                 
 
                       
 
  $ 103,605     $ 38,172     $ 21,056  
 
                 
Income tax expense differs from the amounts computed by applying the U.S. Federal income tax rate of 35% to income before income taxes for the years ended December 31, 2006, 2005 and 2004 as follows (in thousands):
                         
    2006     2005     2004  
Computed expected tax expense
  $ 102,146     $ 37,111     $ 19,918  
Increase (decrease) resulting from:
                       
State and foreign income taxes
    (14 )     242       178  
Other
    1,473       819       960  
 
                 
 
                       
Income tax expense
  $ 103,605     $ 38,172     $ 21,056  
 
                 
The significant components of deferred income taxes at December 31, 2006 and 2005 are as follows (in thousands):
                 
    2006     2005  
Deferred tax assets:
               
Allowance for doubtful accounts
  $ 5,598     $ 1,793  
Operating loss and tax credit carryforwards
    23,183       8,198  
Decommissioning liability
    45,212       45,106  
Deferred interest expense related to exchangeable notes
    35,520        
Other
    13,183       9,476  
 
           
 
    122,696       64,573  
Valuation allowance
    (6,370 )      
 
           
 
               
Net deferred tax assets
    116,326       64,573  
 
           
 
               
Deferred tax liabilities:
               
Property, plant and equipment
    168,523       137,185  
Note receivable
    11,455       11,668  
Goodwill and other intangible assets
    46,810       6,094  
Other
    1,549       1,525  
 
           
 
               
Deferred tax liabilities
    228,337       156,472  
 
           
 
               
Net deferred tax liability
  $ 112,011     $ 91,899  
 
           
The net deferred tax assets reflect 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

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valuation allowance is recognized if it is more likely than not that at least some portion of any deferred tax asset will not be realized. As of December 31, 2006, the Company has recorded a valuation allowance of $6.4 million against its deferred tax assets to reflect the estimated expiration of net operating loss carryforwards.
At December 31, 2006 the Company has approximately $43.4 million in net operating loss carryforwards, which are available to reduce future taxable income. The expiration dates for utilization of the loss carryforwards is 2018 through 2020. Utilization of the net operating loss carryforwards will be subject to annual limitations due to the ownership change limitations provided by the Internal Revenue Code of 1986, as amended. The annual limitations may result in expiration of the net operating loss before full utilization.
As of December 31, 2006, the Company has an estimated $5.3 million foreign tax credit carryforward with expiration dates from 2011 through 2014. As of December 31, 2006, the Company also has various state net operating loss carryforwards of an estimated $30.2 million with expiration dates from 2015 through 2019.
The Company has not provided United States tax expense on earnings of its foreign subsidiaries, since the Company has reinvested or expects to reinvest the undistributed earnings indefinitely. As of December 31, 2006, the undistributed earnings of the Company’s foreign subsidiaries were approximately $46.6 million. If these earnings are repatriated to the United States in the future, additional tax provisions may be required. It is not practicable to estimate the amount of taxes that might be payable on such undistributed earnings.
(10) Stockholders’ Equity
In December 2006, concurrently with the closing of our 1.5% Senior Exchangeable Notes, the Company repurchased and retired 4,739,300 shares of its outstanding common stock at a price of $33.76 per share, or approximately $160 million in the aggregate, in privately negotiated block trades through one of the initial purchasers of the notes.
Also in December 2006, the Company issued 5,369,888 shares of common stock value at $25.39 per share (the average closing market price per share for the five trading day period beginning two trading days before the acquisition announcement date of September 25, 2006) totaling $136.3 million for the acquisition of Warrior Energy Services Corporation.
In connection with the exchangeable note transaction, the Company simultaneously entered into agreements with affiliates of the initial purchasers to purchase call options and sell warrants on its common stock. The Company may exercise the call options it purchased at any time to acquire approximately 8.8 million shares of its common stock at a strike price of $45.58 per share. The owners of the warrants may exercise the warrants to purchase from the Company approximately 8.8 million shares of the Company’s common stock at a price of $59.42 per share, subject to certain anti-dilution and other customary adjustments. The warrants may be settled in cash, in shares or in a combination of cash and shares, at the Company’s option. The Company paid $96 million (exclusive of a $35.5 million tax benefit) to acquire the call options and received $60.4 million as a result of the sale of the warrants. The $60.5 million purchase of the call options, net of the related tax benefit, was recorded as a reduction to stockholders’ equity and the sale of the warrants was recorded as an increase to stockholders’ equity in accordance with the guidance in EITF Issue No. 00-19, “Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company’s Own Stock.” Subsequent changes in the fair value of the call options and warrants will not be recognized as long as the instruments remain classified in stockholders’ equity.
In 2004, the Company sold 11,151,121 shares of common stock (including 1,454,494 shares pursuant to the exercise of the underwriters’ over-allotment option) that generated net proceeds of approximately $130 million, after deducting underwriting discounts and commissions and the offering expenses. The Company used most of the net proceeds to repurchase 9,696,627 shares of its common stock from First Reserve Fund VII, Limited Partnership and First Reserve Fund VIII, L.P. The shares repurchased by the Company from the First Reserve funds were retired immediately upon repurchase.

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(11) Reduction in Value of Assets
During the year ended December 31, 2005, the Company reduced the value of two of its mature oil and gas properties by approximately $2.1 million due to well issues affecting production rates and operating costs. The Company deemed it to be uneconomical to perform additional production enhancement work to maintain production at these properties.
Also during the year ended December 31, 2005, the Company’s oil spill containment boom manufacturing facility suffered damage from Hurricane Katrina and experienced difficulty in resuming normal business operations. As a result, the Company elected not to reopen this manufacturing facility and sell the remaining oil spill containment boom inventory. The value of the assets of this business (which consist primarily of inventory and property and equipment) were reduced by approximately $1.1 million to their estimated net realizable value.
In the first quarter of 2006, the Company sold its environmental subsidiary for approximately $18.7 million in cash. The Company reduced the net asset value of this subsidiary by $3.8 million in 2005 to the approximate sales price.
(12) Gain on Sale of Liftboats
Effective June 1, 2005, the Company sold 17 of its rental liftboats with leg-lengths from 105 feet to 135 feet for $19.6 million in cash (net of costs to sell). This constituted all of the Company’s rental fleet of liftboats with leg-lengths of 135 feet or less. The Company recorded a gain of $3.5 million in the year ended December 31, 2005 as a result of this transaction.
(13) Profit-Sharing Plan
The Company maintains a defined contribution profit-sharing plan for employees who have satisfied minimum service and age requirements. Employees may contribute up to 75% of their earnings to the plans limited by the annual dollar limitations imposed by the Internal Revenue Service. The Company provides a discretionary match, not to exceed 5% of an employee’s salary. The Company made contributions of approximately $2.7 million, $1.9 million and $1.7 million in 2006, 2005 and 2004, respectively.
The Company has a nonqualified defined contribution deferred compensation plan which allows certain highly-compensated employees the option to defer up to 75% of their salary and up to 100% of their bonus compensation to the plan. Payments are made to participants based on their annual enrollment elections and plan balance. Participants earn a return on their deferred compensation that is based on hypothetical investments in certain mutual funds. Changes in market value of these hypothetical participant investments are reflected as an adjustment to the deferred compensation liability of the Company with an offset to compensation expense. As of December 31, 2006 and 2005, the liability of the Company to the participants was approximately $3.9 million and $1.5 million, respectively, and is recorded in Other Long-Term Liabilities, which reflects the accumulated participant deferrals and earnings as of that date. The Company makes contributions equal to the participant deferrals into life insurance which is invested in mutual funds similar to the participants’ elections. A change in market value of the life insurance is reflected as an adjustment to the deferred compensation plan asset with an offset to interest income or expense. As of December 31, 2006 and 2005, the deferred contribution plan asset was approximately $4.3 million and $1.4 million, respectively, and is recorded in Intangible and Other Long-Term Assets.
(14) Commitments and Contingencies
The Company leases many of its office, service and assembly facilities under operating leases. The leases expire at various dates over the next several years. Total rent expense was approximately $4.2 million in 2006, $4.3 million in 2005 and $4.2 million in 2004. Future minimum lease payments under non-cancelable leases for the five years ending December 31, 2007 through 2011 and thereafter are as follows (amounts in thousands): $7,003, $4,939, $2,932, $1,628, $973 and $13,692, respectively.
From time to time, the Company is involved in litigation arising out of operations in the normal course of business. In 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.

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(15) Segment Information
Business Segments
The Company has four reportable segments: well intervention, rental tools, marine, and oil and gas. The well intervention segment provides: production-related services used to enhance, extend and maintain oil and gas production, which include mechanical wireline, hydraulic workover and snubbing, well control, coiled tubing, electric line, pumping and stimulation and wellbore evaluation services; well plug and abandonment services; and other oilfield services used to support drilling and production operations. The rental tools segment rents and sells stabilizers, drill pipe, tubulars and specialized equipment for use with onshore and offshore oil and gas well drilling, completion, production and workover activities. It also provides on-site accommodations and bolting and machining services. The marine segment operates liftboats for production service activities, as well as oil and gas production facility maintenance, construction operations and platform removals. The oil and gas segment acquires mature oil and gas properties and produces and sells any remaining economic oil and gas reserves. Oil and gas eliminations represent products and services provided to the oil and gas segment by the Company’s three other segments.
The accounting policies of the reportable segments are the same as those described in note 1 of these Notes to the Consolidated Financial Statements. The Company evaluates the performance of its operating segments based on operating profits or losses. Segment revenues reflect direct sales of products and services for that segment, and each segment records direct expenses related to its employees and its operations. Identifiable assets are primarily those assets directly used in the operations of each segment. The equity-method investment in Coldren Resources of approximately $63.6 million is included in the identifiable assets of the oil and gas segment.
Summarized financial information concerning the Company’s segments as of December 31, 2006, 2005 and 2004 and for the years then ended is shown in the following tables (in thousands):
                                                 
                                    Oil & Gas    
    Well   Rental                   Eliminations   Consolid.
2006   Interven.   Tools   Marine   Oil & Gas   & Unallocated   Total
     
Revenues
  $ 469,110     $ 371,155     $ 140,115     $ 127,682     $ (14,241 )   $ 1,093,821  
Cost of services, rentals, and sales
    269,631       115,898       56,189       70,028       (14,241 )     497,505  
Depreciation, depletion, amortization and accretion
    18,810       52,234       8,600       31,367             111,011  
General and administrative
    77,758       70,306       11,432       8,920             168,416  
Income from operations
    102,911       132,717       63,894       17,367             316,889  
Interest expense, net
                            (22,950 )     (22,950 )
Interest income
                      1,194       3,418       4,612  
Loss on early extinguishment of debt
                            (12,596 )     (12,596 )
Earnings from equity-method investments
                      5,891             5,891  
     
 
                                               
Income before income taxes
  $ 102,911     $ 132,717     $ 63,894     $ 24,452     $ (32,128 )   $ 291,846  
     
 
                                               
Identifiable assets
  $ 807,358     $ 533,928     $ 187,597     $ 318,297     $ 27,298     $ 1,874,478  
 
                                               
Capital expenditures
  $ 54,104     $ 111,270     $ 10,412     $ 64,237     $ 2,913     $ 242,936  

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                                    Oil & Gas    
    Well   Rental                   Eliminations   Consolid.
2005   Interven.   Tools   Marine   Oil & Gas   & Unallocated   Total
     
Revenues
  $ 339,609     $ 243,536     $ 87,267     $ 78,911     $ (13,989 )   $ 735,334  
Cost of services, rentals, and sales
    213,638       82,562       47,989       45,804       (13,989 )     376,004  
Depreciation, depletion, amortization and accretion
    18,135       42,445       8,214       20,494             89,288  
General and administrative
    71,027       54,533       9,889       5,540             140,989  
Reduction in value of assets
    4,850                   2,144             6,994  
Gain on sale of liftboats
                3,544                   3,544  
Income from operations
    31,959       63,996       24,719       4,929             125,603  
Interest expense, net
                            (21,862 )     (21,862 )
Interest income
                      1,160       1,041       2,201  
Earnings from equity-method investments
          1,339                         1,339  
Reduction in value of equity- method investment
          (1,250 )                       (1,250 )
     
 
                                               
Income before income taxes
  $ 31,959     $ 64,085     $ 24,719     $ 6,089     $ (20,821 )   $ 106,031  
     
 
                                               
Identifiable assets
  $ 332,996     $ 405,527     $ 203,718     $ 147,667     $ 7,342     $ 1,097,250  
 
                                               
Capital expenditures
  $ 24,847     $ 70,227     $ 10,399     $ 19,693     $     $ 125,166  
                                                 
                                    Oil & Gas    
    Well   Rental                   Eliminations   Consolid.
2004   Interven.   Tools   Marine   Oil & Gas   & Unallocated   Total
     
Revenues
  $ 295,690     $ 170,064     $ 69,808     $ 37,008     $ (8,231 )   $ 564,339  
Costs of services, rentals and sales
    189,858       57,353       49,581       21,547       (8,231 )     310,108  
Depreciation, depletion, amortization and accretion
    17,435       32,527       7,362       10,013             67,337  
General and administrative
    58,703       42,165       7,085       2,652             110,605  
Income from operations
    29,694       38,019       5,780       2,796             76,289  
Interest expense, net
                            (22,476 )     (22,476 )
Interest income
                      1,648       118       1,766  
Earnings from equity-method investments
          1,329                         1,329  
     
 
                                               
Income before income taxes
  $ 29,694     $ 39,348     $ 5,780     $ 4,444     $ (22,358 )   $ 56,908  
     
 
                                               
Identifiable assets
  $ 313,431     $ 357,762     $ 184,928     $ 141,179     $ 6,613     $ 1,003,913  
 
                                               
Capital expenditures
  $ 12,735     $ 50,687     $ 5,523     $ 5,180     $     $ 74,125  
Geographic Segments
The Company attributes revenue to various countries based on the location of where services are performed or the destination of the rental tools or products sold. Long-lived assets consist primarily of property, plant, and equipment and are attributed to various countries based on the physical location of the asset at a given fiscal year-end. The 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,
    2006   2005   2004   2006   2005
United States
  $ 924,582     $ 636,062     $ 476,771     $ 715,899     $ 492,602  
Other Countries
    169,239       99,272       87,568       88,329       42,360  
         
 
                                       
Total
  $ 1,093,821     $ 735,334     $ 564,339     $ 804,228     $ 534,962  
         
(16) Interim Financial Information (Unaudited)
The following is a summary of consolidated interim financial information for the years ended December 31, 2006 and 2005 (amounts in thousands, except per share data):
                                 
    Three Months Ended
    March 31   June 30   Sept. 30   Dec. 31
2006
                               
Revenues
  $ 222,469     $ 261,759     $ 290,517     $ 319,076  
Gross profit
    115,009       141,771       161,430       178,106  
Net income
    32,168       38,727       55,158       62,188  
 
                               
Earnings per share:
                               
Basic
  $ 0.40     $ 0.49     $ 0.69     $ 0.78  
Diluted
    0.40       0.48       0.68       0.76  
                                 
    Three Months Ended
    March 31   June 30   Sept. 30   Dec. 31
2005
                               
Revenues
  $ 173,247     $ 190,000     $ 184,101     $ 187,986  
Gross profit
    86,829       99,348       82,704       90,449  
Net income
    17,209       25,054       9,358       16,238  
 
                               
Earnings per share:
                               
Basic
  $ 0.22     $ 0.32     $ 0.12     $ 0.20  
Diluted
    0.22       0.32       0.12       0.20  
(17) Financial Information Related to Guarantor Subsidiaries
In May 2006, SESI, L.L.C. (Issuer), a wholly-owned subsidiary of Superior Energy Services, Inc. (Parent), issued $300 million of 6 7/8% Senior Notes due 2014 at 98.489%. In December 2006, the Issuer issued $400 million of 1.5% Senior Exchangeable Notes due 2026. The Parent, along with substantially all of its subsidiaries, fully and unconditionally guaranteed the Senior Notes and the 1.5% Senior Exchangeable Notes and such guarantees are joint and several. All of the guarantor subsidiaries are wholly-owned subsidiaries of the Issuer. Domestic income taxes are paid by the Parent through a consolidated tax return and are accounted for by the Parent. The following tables present the condensed consolidating balance sheets as of December 31, 2006 and 2005 and the consolidating statements of operations and cash flows for the years ended December 31, 2006, 2005 and 2004.

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidating Balance Sheets
December 31, 2006
(in thousands)
                                                 
                    Guarantor     Non-Guarantor              
    Parent     Issuer     Subsidiaries     Subsidiaries     Eliminations     Consolidated  
ASSETS
                                               
Current assets:
                                               
Cash and cash equivalents
  $     $ 1,608     $ 14,775     $ 22,587     $     $ 38,970  
Accounts receivable, net
          3,764       275,477       39,390       (14,831 )     303,800  
Income taxes receivable
    7,242                         (4,612 )     2,630  
Current portion of notes receivable
                14,824                   14,824  
Prepaid insurance and other
          16,582       40,456       2,525             59,563  
 
                                   
 
                                               
Total current assets
    7,242       21,954       345,532       64,502       (19,443 )     419,787  
 
                                   
 
                                               
Property, plant and equipment, net
          2,622       738,446       63,160             804,228  
Goodwill, net
                417,979       26,708             444,687  
Notes receivable
                16,137                   16,137  
Equity-method investments
    124,271       510,163       63,627             (633,458 )     64,603  
Intangible and other long-term assets, net
          23,823       101,097       116             125,036  
 
                                   
 
                                               
Total assets
  $ 131,513     $ 558,562     $ 1,682,818     $ 154,486     $ (652,901 )   $ 1,874,478  
 
                                   
 
                                               
LIABILITIES AND STOCKHOLDERS’ EQUITY
                                               
Current liabilities:
                                               
Accounts payable
  $     $ 1,045     $ 58,528     $ 20,709     $ (14,831 )   $ 65,451  
Accrued expenses
    505       27,671       104,866       8,642             141,684  
Income taxes payable
                      4,612       (4,612 )      
Current portion of decommissioning liabilities
                35,150                   35,150  
Current maturities of long-term debt
                      810             810  
 
                                   
 
                                               
Total current liabilities
    505       28,716       198,544       34,773       (19,443 )     243,095  
 
                                   
 
                                               
Deferred income taxes
    108,649                   3,362             112,011  
Decommissioning liabilities
                87,046                   87,046  
Long-term debt
          695,719             15,786             711,505  
Intercompany payables/(receivables)
    (224,208 )     (79,487 )     782,022       23,507       (501,834 )      
Other long-term liabilities
    6,197       3,936                         10,133  
 
                                               
Stockholders’ equity:
                                               
Preferred stock of $.01 par value.
                                   
Common stock of $.001 par value.
    81                   101       (101 )     81  
Additional paid in capital
    411,374       127,173             4,350       (131,523 )     411,374  
Accumulated other comprehensive income
                      10,288             10,288  
Retained earnings (deficit)
    (171,085 )     (217,495 )     615,206       62,319             288,945  
 
                                   
 
                                               
Total stockholders’ equity
    240,370       (90,322 )     615,206       77,058       (131,624 )     710,688  
 
                                   
 
                                               
Total liabilities and stockholders’ equity
  $ 131,513     $ 558,562     $ 1,682,818     $ 154,486     $ (652,901 )   $ 1,874,478  
 
                                   

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidating Balance Sheets
December 31, 2005
(in thousands)
                                                 
                    Guarantor     Non-Guarantor              
    Parent     Issuer     Subsidiaries     Subsidiaries     Eliminations     Consolidated  
ASSETS
                                               
Current assets:
                                               
Cash and cash equivalents
  $     $ 21,414     $ 19,421     $ 13,622     $     $ 54,457  
Accounts receivable, net
          3,748       180,670       23,332       (11,385 )     196,365  
Current portion of notes receivable
                2,364                   2,364  
Prepaid insurance and other
          3,039       46,237       1,840             51,116  
 
                                   
 
                                               
Total current assets
          28,201       248,692       38,794       (11,385 )     304,302  
 
                                   
 
                                               
Property, plant and equipment, net
                481,265       53,697             534,962  
Goodwill, net
                196,696       23,368             220,064  
Notes receivable
                29,483                   29,483  
Equity-method investments
    124,271       203,083             953       (327,354 )     953  
Other assets, net
          6,390       553       543             7,486  
 
                                   
 
                                               
Total assets
  $ 124,271     $ 237,674     $ 956,689     $ 117,355     $ (338,739 )   $ 1,097,250  
 
                                   
 
                                               
LIABILITIES AND STOCKHOLDERS’ EQUITY
                                               
Current liabilities:
                                               
Accounts payable
  $     $ 821     $ 34,790     $ 17,809     $ (11,385 )   $ 42,035  
Accrued expenses
    269       17,300       46,025       6,332             69,926  
Income taxes payable
    9,917                   1,436             11,353  
Fair value of commodity derivative instruments
                10,792                   10,792  
Current portion of decommissioning liabilities
                14,268                   14,268  
Current maturities of long-term debt
                      810             810  
 
                                   
 
                                               
Total current liabilities
    10,186       18,121       105,875       26,387       (11,385 )     149,184  
 
                                   
 
                                               
Deferred income taxes
    89,108                   2,791             91,899  
Decommissioning liabilities
                107,641                   107,641  
Long-term debt
          200,000             16,596             216,596  
Intercompany payables/(receivables)
    (332,937 )     31,751       467,362       29,554       (195,730 )      
Other long-term liabilities
    6,088       1,458       10                   7,556  
 
                                               
Stockholders’ equity:
                                               
Preferred stock of $.01 par value
                                   
Common stock of $.001 par value
    79                   101       (101 )     79  
Additional paid in capital
    428,507       127,173             4,350       (131,523 )     428,507  
Accumulated other comprehensive income (loss), net
                (6,799 )     1,883             (4,916 )
Retained earnings (deficit)
    (76,760 )     (140,829 )     282,600       35,693             100,704  
 
                                   
 
                                               
Total stockholders’ equity
    351,826       (13,656 )     275,801       42,027       (131,624 )     524,374  
 
                                   
 
                                               
Total liabilities and stockholders’ equity
  $ 124,271     $ 237,674     $ 956,689     $ 117,355     $ (338,739 )   $ 1,097,250  
 
                                   

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidating Statements of Operations
Year Ended December 31, 2006
(in thousands)
                                                 
                    Guarantor     Non-Guarantor              
    Parent     Issuer     Subsidiaries     Subsidiaries     Eliminations     Consolidated  
Oilfield service and rental revenues
  $     $     $ 868,831     $ 125,299     $ (27,991 )   $ 966,139  
Oil and gas revenues
                127,682                   127,682  
 
                                   
 
                                               
Total revenues
                996,513       125,299       (27,991 )     1,093,821  
 
                                   
 
                                               
Cost of oilfield services and rentals
                390,065       65,403       (27,991 )     427,477  
Cost of oil and gas sales
                70,028                   70,028  
 
                                   
 
                                               
Total cost of services, rentals and sales
                460,093       65,403       (27,991 )     497,505  
 
                                   
 
                                               
Depreciation, depletion, amortization and accretion
          291       100,818       9,902             111,011  
General and administrative expenses
    501       45,168       109,964       12,783             168,416  
 
                                   
 
                                               
Income from operations
    (501 )     (45,459 )     325,638       37,211             316,889  
 
                                   
 
                                               
Other income (expense):
                                               
Interest expense, net
          (21,239 )     (598 )     (1,113 )           (22,950 )
Interest income
          2,605       1,698       309             4,612  
Loss on early extinguishment of debt
          (12,596 )                       (12,596 )
Earnings from equity-method investments
          23       5,868                   5,891  
 
                                   
 
                                               
Income before income taxes
    (501 )     (76,666 )     332,606       36,407             291,846  
 
                                               
Income taxes
    93,824                   9,781             103,605  
 
                                   
 
                                               
Net income (loss)
  $ (94,325 )   $ (76,666 )   $ 332,606     $ 26,626     $     $ 188,241  
 
                                   

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidating Statements of Operations
Year Ended December 31, 2005
(in thousands)
                                                 
                    Guarantor     Non-Guarantor              
    Parent     Issuer     Subsidiaries     Subsidiaries     Eliminations     Consolidated  
Oilfield service and rental revenues
  $     $     $ 606,415     $ 76,102     $ (26,094 )   $ 656,423  
Oil and gas revenues
                78,911                   78,911  
 
                                   
 
                                               
Total revenues
                685,326       76,102       (26,094 )     735,334  
 
                                   
 
                                               
Cost of oilfield services and rentals
                313,386       42,908       (26,094 )     330,200  
Cost of oil and gas sales
                45,804                   45,804  
 
                                   
 
                                               
Total cost of services, rentals and sales
                359,190       42,908       (26,094 )     376,004  
 
                                   
 
                                               
Depreciation, depletion, amortization and accretion
                81,817       7,471             89,288  
General and administrative expenses
    460       29,301       101,857       9,371             140,989  
Reduction in value of assets
                6,994                   6,994  
Gain on sale of liftboats
                3,544                   3,544  
 
                                   
 
                                               
Income from operations
    (460 )     (29,301 )     139,012       16,352             125,603  
 
                                   
 
                                               
Other income (expense):
                                               
Interest expense, net
          (20,585 )     (6 )     (1,271 )           (21,862 )
Interest income
          822       1,194       185             2,201  
Earnings from equity-method investments
                      1,339             1,339  
Reduction in value of equity-method investment
                      (1,250 )           (1,250 )
 
                                   
 
                                               
Income before income taxes
    (460 )     (49,064 )     140,200       15,355             106,031  
 
                                               
Income taxes
    33,629                   4,543             38,172  
 
                                   
 
                                               
Net income (loss)
  $ (34,089 )   $ (49,064 )   $ 140,200     $ 10,812     $     $ 67,859  
 
                                   

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidating Statements of Operations
Year Ended December 31, 2004
(in thousands)
                                                 
                    Guarantor     Non-Guarantor              
    Parent     Issuer     Subsidiaries     Subsidiaries     Eliminations     Consolidated  
Oilfield service and rental revenues
  $     $     $ 488,745     $ 56,666     $ (18,080 )   $ 527,331  
Oil and gas revenues
                37,008                   37,008  
 
                                   
 
                                               
Total revenues
                525,753       56,666       (18,080 )     564,339  
 
                                   
 
                                               
Cost of oilfield services and rentals
                276,141       30,500       (18,080 )     288,561  
Cost of oil and gas sales
                21,547                   21,547  
 
                                   
 
                                               
Total cost of services, rentals and sales
                297,688       30,500       (18,080 )     310,108  
 
                                   
 
                                               
Depreciation, depletion, amortization
                62,185       5,152             67,337  
and accretion
                                               
General and administrative expenses
    429       13,966       87,420       8,790             110,605  
 
                                   
 
                                               
Income from operations
    (429 )     (13,966 )     78,460       12,224             76,289  
 
                                   
 
                                               
Other income (expense):
                                               
Interest expense, net
          (21,108 )     (102 )     (1,266 )           (22,476 )
Interest income
          51       1,656       59             1,766  
Earnings from equity-method investments
                      1,329             1,329  
 
                                   
 
                                               
Income before income taxes
    (429 )     (35,023 )     80,014       12,346             56,908  
 
                                               
Income taxes
    17,708                   3,348             21,056  
 
                                   
 
                                               
Net income (loss)
  $ (18,137 )   $ (35,023 )   $ 80,014     $ 8,998     $     $ 35,852  
 
                                   

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2006
(in thousands)
                                         
                            Non-        
                    Guarantor     Guarantor        
    Parent     Issuer     Subsidiaries     Subsidiaries     Consolidated  
Cash flows from operating activities:
                                       
Net income (loss)
  $ (94,325 )   $ (76,666 )   $ 332,606     $ 26,626     $ 188,241  
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
                                       
Depreciation, depletion, amortization and accretion
          291       100,818       9,902       111,011  
Deferred income taxes
    18,338                   (2,675 )     15,663  
Stock-based compensation expense
          6,159                   6,159  
Earnings from equity-method investments
          (23 )     (5,868 )           (5,891 )
Write-off of debt acquisition costs
          2,817                   2,817  
Amortization of debt acquisition costs and note discount
            1,321                   1,321  
Changes in operating assets and liabilities, net of acquisitions and dispositions:
                                       
Receivables
          (16 )     (73,861 )     (14,421 )     (88,298 )
Other, net
    (3,789 )     (82 )     12,553       5,210       13,892  
Accounts payable
          225       4,694       2,340       7,259  
Accrued expenses
    236       6,583       34,725       1,835       43,379  
Decommissioning liabilities
                (2,255 )           (2,255 )
Income taxes
    (15,971 )                 2,887       (13,084 )
 
                             
Net cash provided by (used in) operating activities
    (95,511 )     (59,391 )     403,412       31,704       280,214  
 
                             
Cash flows from investing activities:
                                       
Payments for capital expenditures
          (2,913 )     (225,411 )     (14,612 )     (242,936 )
Acquisitions of businesses, net of cash acquired
          (239,339 )                 (239,339 )
Acquisitions of oil and gas properties, net of cash acquired
                (46,631 )           (46,631 )
Cash proceeds from sale of subsidiary, net of cash sold
          18,343                   18,343  
Cash contributed to equity-method investment
                (57,781 )           (57,781 )
Other
          (13,947 )     313             (13,634 )
Intercompany receivables/payables
    286,878       (199,669 )     (78,548 )     (8,661 )      
 
                             
Net cash provided by (used in) investing activities
    286,878       (437,525 )     (408,058 )     (23,273 )     (581,978 )
 
                             
Cash flows from financing activities:
                                       
Proceeds from long-term debt
          695,467                   695,467  
Principal payments on long-term debt
          (200,000 )           (810 )     (200,810 )
Payment of debt acquisition costs
          (18,357 )                 (18,357 )
Purchase of option
    (96,000 )                       (96,000 )
Sale of warrant
    60,400                         60,400  
Proceeds from exercise of stock options
    2,803                         2,803  
Tax benefit from exercise of stock options
    1,429                         1,429  
Purchase and retirement of stock
    (159,999 )                       (159,999 )
 
                             
Net cash provided by (used in) financing activities
    (191,367 )     477,110             (810 )     284,933  
 
                             
Effect of exchange rate changes on cash
                      1,344       1,344  
 
                             
Net increase (decrease) in cash and cash equivalents
          (19,806 )     (4,646 )     8,965       (15,487 )
Cash and cash equivalents at beginning of year
          21,414       19,421       13,622       54,457  
 
                             
Cash and cash equivalents at end of year
  $     $ 1,608     $ 14,775     $ 22,587     $ 38,970  
 
                             

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2005
(in thousands)
                                         
                            Non-        
                    Guarantor     Guarantor        
    Parent     Issuer     Subsidiaries     Subsidiaries     Consolidated  
Cash flows from operating activities:
                                       
Net income (loss)
  $ (34,089 )   $ (49,064 )   $ 140,200     $ 10,812     $ 67,859  
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
                                       
Depreciation, depletion, amortization and accretion
                81,817       7,471       89,288  
Deferred income taxes
    509                   (67 )     442  
Reduction in value of assets and equity-method investment
                6,994       1,250       8,244  
Earnings from equity-method investments
                      (1,339 )     (1,339 )
Amortization of debt acquisition costs and note discount
          1,127                   1,127  
Gain on sale of liftboats
                (3,544 )           (3,544 )
Changes in operating assets and liabilities, net of acquisitions:
                                       
Receivables
          (2,026 )     (21,849 )     (8,220 )     (32,095 )
Other, net
    335       568       (13,733 )     1,567       (11,263 )
Accounts payable
          35       (2,282 )     7,943       5,696  
Accrued expenses
    253       4,006       8,844       3,496       16,599  
Decommissioning liabilities
                (8,772 )           (8,772 )
Income taxes
    25,886                   251       26,137  
 
                             
 
                                       
Net cash provided by (used in) operating activities
    (7,106 )     (45,354 )     187,675       23,164       158,379  
 
                             
 
                                       
Cash flows from investing activities:
                                       
Payments for capital expenditures
                (111,825 )     (13,341 )     (125,166 )
Acquisitions of businesses, net of cash acquired
          (6,435 )                 (6,435 )
Acquisitions of oil and gas properties, net of cash acquired
                3,686             3,686  
Cash proceeds from sale of equity-method investment
                      12,489       12,489  
Cash proceeds from the sale of liftboats, net
                19,588             19,588  
Other
          (1,410 )     313             (1,097 )
Intercompany receivables/payables
    (11,055 )     110,004       (85,189 )     (13,760 )      
 
                             
 
                                       
Net cash provided by (used in) investing activities
    (11,055 )     102,159       (173,427 )     (14,612 )     (96,935 )
 
                             
 
                                       
Cash flows from financing activities:
                                       
Principal payments on long-term debt
          (38,500 )           (810 )     (39,310 )
Payment of debt acquisition costs
          (439 )                 (439 )
Proceeds from exercise of stock options
    18,161                         18,161  
 
                             
 
                                       
Net cash provided by (used in) financing activities
    18,161       (38,939 )           (810 )     (21,588 )
 
                             
 
                                       
Effect of exchange rate changes on cash
                      (680 )     (680 )
 
                             
 
                                       
Net increase (decrease) in cash
          17,866       14,248       7,062       39,176  
 
                                       
Cash and cash equivalents at beginning of period
          3,548       5,173       6,560       15,281  
 
                             
 
                                       
Cash and cash equivalents at end of period
  $     $ 21,414     $ 19,421     $ 13,622     $ 54,457  
 
                             

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidating Statements of Cash Flows
Year Ended December 31,2004
(in thousands)
                                         
                            Non-        
                    Guarantor     Guarantor        
    Parent     Issuer     Subsidiaries     Subsidiaries     Consolidated  
Cash flows from operating activities:
                                       
Net income (loss)
  $ (18,137 )   $ (35,023 )   $ 80,014     $ 8,998     $ 35,852  
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
                                       
Depreciation, depletion, amortization and accretion
                62,185       5,152       67,337  
Deferred income taxes
    14,400                   834       15,234  
Earnings from equity-method investments
                      (1,329 )     (1,329 )
Amortization of debt acquisition costs and note discount
          887                   887  
Changes in operating assets and liabilities, net of acquisitions:
                                       
Receivables
          (1,416 )     (28,517 )     (5,346 )     (35,279 )
Other, net
          (774 )     (7,278 )     (1,294 )     (9,346 )
Accounts payable
          64       11,012       5,066       16,142  
Accrued expenses
    (5 )     (8,034 )     21,241       664       13,866  
Decommissioning liabilities
                (9,157 )           (9,157 )
Income taxes
    (3,690 )                 814       (2,876 )
 
                             
 
                                       
Net cash provided by (used in) operating activities
    (7,432 )     (44,296 )     129,500       13,559       91,331  
 
                             
 
                                       
Cash flows from investing activities:
                                       
Payments for capital expenditures
                (69,385 )     (4,740 )     (74,125 )
Acquisitions of businesses, net of cash acquired
          (24,361 )                 (24,361 )
Acquisitions of oil and gas properties, net of cash acquired
                (10,676 )           (10,676 )
Intercompany receivables/payables
    (19,666 )     76,090       (50,990 )     (5,434 )      
 
                             
 
                                       
Net cash provided by (used in) investing activities
    (19,666 )     51,729       (131,051 )     (10,174 )     (109,162 )
 
                             
 
                                       
Cash flows from financing activities:
                                       
Principal payments on long-term debt
          (12,903 )           (810 )     (13,713 )
Payment of debt acquisition costs
          (60 )                 (60 )
Proceeds from exercise of stock options
    10,271                         10,271  
Proceeds from issuance of stock
    130,265                         130,265  
Purchase and retirement of stock
    (113,438 )                       (113,438 )
 
                             
 
                                       
Net cash provided by (used in) financing activities
    27,098       (12,963 )           (810 )     13,325  
 
                             
 
                                       
Effect of exchange rate changes on cash
                      (7 )     (7 )
 
                             
 
                                       
Net increase (decrease) in cash
          (5,530 )     (1,551 )     2,568       (4,513 )
 
                                       
Cash and cash equivalents at beginning of period
          9,078       6,724       3,992       19,794  
 
                             
 
                                       
Cash and cash equivalents at end of period
  $     $ 3,548     $ 5,173     $ 6,560     $ 15,281  
 
                             

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(18) Supplementary Oil and Natural Gas Disclosures (Unaudited)
The Company’s December 31, 2006, 2005 and 2004 estimates of proved reserves are based on reserve reports prepared by DeGolyer and MacNaughton, independent petroleum engineers. Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. This data may also change substantially over time as a result of multiple factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures. Proved reserves are estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
The following table sets forth the 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, 2003
    190       3,224  
Purchase of reserves in place
    9,232       17,968  
Revisions
    88       11,407  
Production
    (390 )     (3,219 )
 
           
 
               
December 31, 2004
    9,120       29,380  
 
           
Purchase of reserves in place
    168       2,925  
Revisions
    1,036       (5,294 )
Production
    (1,221 )     (3,323 )
 
           
 
               
December 31, 2005
    9,103       23,688  
 
           
Purchase of reserves in place and additions
    674       17,249  
Revisions
    (265 )     187  
Production
    (1,591 )     (5,483 )
 
           
 
               
December 31, 2006
    7,921       35,641  
 
           
 
               
Proved-developed reserves:
               
December 31, 2004
    7,731       25,542  
December 31, 2005
    7,554       21,703  
December 31, 2006
    6,709       28,982  
Since January 1, 2005 no crude oil or natural gas reserve information has been filed with, or included in any report to any federal authority or agency other than the SEC and the Energy Information Administration (“EIA”). The Company files Form 23, including reserve and other information with the EIA.
Costs incurred for oil and natural gas property acquisition and development activities for the years ended December 31, 2006, 2005 and 2004 are as follows (in thousands):

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    Years Ended December 31,  
    2006     2005     2004  
Acquisition of properties — proved
  $ 45,948     $ 9,015     $ 81,356  
Development costs
    63,396       19,867       4,707  
 
                 
 
                       
Total costs incurred
  $ 109,344     $ 28,882     $ 86,063  
 
                 
Standardized Measure of Discounted Future Net Cash Flows Relating to Reserves
The following information has been developed utilizing procedures prescribed by Statement of Financial Accounting Standards No. 69 (FAS No. 69), “Disclosure about Oil and Gas Producing Activities.” It may be useful for certain comparative purposes, but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company.
The Company believes that the following factors should be taken into account in reviewing the following information: (1) future costs and selling prices will differ from those required to be used in these calculations; (2) due to future market conditions and governmental regulations, actual rates of production achieved in future years may vary significantly from the rate of production assumed in the calculations; (3) selection of a 10% discount rate is arbitrary and may not be reasonable as a measure of the relative risk inherent in realizing future net oil and gas revenues; and (4) future net revenues may be subject to different rates of income taxation.
Under the Standardized Measure, future cash inflows were estimated by applying period-end oil and natural gas prices adjusted for differentials provided by the Company. Future cash inflows were reduced by estimated future development, abandonment and production costs based on period-end costs in order to arrive at net cash flow before tax. Future income tax expense has been computed by applying period-end statutory tax rates to aggregate future net cash flows, reduced by the tax basis of the properties involved and tax carryforwards. Use of a 10% discount rate is required by FAS No. 69.
The 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):
                         
    2006     2005     2004  
Future cash inflows
  $ 682,384     $ 792,246     $ 587,277  
Future production costs
    (220,108 )     (155,282 )     (148,610 )
Future development and abandonment costs
    (207,676 )     (195,415 )     (153,230 )
Future income tax expense
    (59,976 )     (171,058 )     (119,567 )
 
                 
 
                       
Future net cash flows after income taxes
    194,624       270,491       165,870  
10% annual discount for estimated timing of cash flows
    15,883       65,386       29,363  
 
                 
 
                       
Standardized measure of discounted future net cash flows
  $ 178,741     $ 205,105     $ 136,507  
 
                 
A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves for the years ended December 31, 2006, 2005 and 2004 is as follows (in thousands):

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    2006     2005     2004  
Beginning of the period
  $ 205,105     $ 136,507     $ 3,990  
Sales and transfers of oil and natural gas produced, net of production costs
    (55,184 )     (34,563 )     (15,467 )
Net changes in prices and production costs
    (147,633 )     156,992       949  
Revisions of quantity estimates
    (7,071 )     4,314       46,040  
Development costs incurred
    (64,254 )     19,867       4,707  
Changes in estimated development costs
    47,096       (46,113 )     (99,253 )
Extensions and discoveries
    36,906              
Purchase and sales of reserves in place
    70,304       18,408       282,935  
Changes in production rates (timing) and other
    (22,080 )     (25,536 )     (3,238 )
Accretion of discount
    33,152       22,123       656  
Net change in income taxes
    82,401       (46,894 )     (84,812 )
 
                 
 
&nb