10-K 1 h54349e10vk.htm FORM 10-K - ANNUAL REPORT e10vk
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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, 2007
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
(State or other jurisdiction of incorporation or organization)
  75-2379388
(I.R.S. Employer Identification No.)
     
1105 Peters Road
Harvey, LA
(Address of principal executive offices)
  70058
(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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
             
Large accelerated filer þ   Accelerated filer o   Non-accelerated filer o   Smaller reporting company o
    (Do not check if a smaller reporting company)
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, 2007 based on the closing price on the New York Stock Exchange on that date was $3,214,596,000.
The number of shares of the registrant’s common stock outstanding on February 18, 2008 was 80,775,931.
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, 2007
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 Subsidiaries of the Company
 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, 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 174 offshore wireline and electric line units, 97 land wireline and electric line units, 33 coiled tubing 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 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 March 2008, after which time, this derrick barge will be brought into the Gulf of Mexico. We are also constructing a second 880-

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ton derrick barge with an expected delivery date in the third quarter of 2008. We also manufacture and sell specialized drilling rig instrumentation equipment.
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 oil and gas activities in the Gulf of Mexico and in North Louisiana, Arkansas, Oklahoma, Colorado and Wyoming. Our rental tools segment also conducts operations in Venezuela, Trinidad, Mexico, Colombia, Brazil, 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, 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. We have contracted to construct two 175 foot liftboats, one of which was delivered in February 2008 and the other is scheduled to be delivered in June 2008.
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, 2007, we had interests in 31 offshore blocks containing 79 structures and approximately 149 producing wells. As of December 31, 2007, we had reserves of approximately 13.7 million barrels of oil equivalent (mmboe) with a PV-10 (future net revenue discounted at 10%) of $496.7 million and approximately 90% of our reserves were classified as proved developed. The oil and natural gas information contained herein does not include the properties or reserves owned by our equity-method investee, Beryl Oil and Gas, L.P., formerly known as Coldren Resources LP.
In February 2008, we entered into a purchase agreement to sell 75% of our interest in SPN Resources for approximately $165 million in cash, subject to certain conditions. The transaction is expected to close during the first quarter of 2008. We will retain the preferential rights on all service work and have agreed to perform, on a fixed price basis, the decommissioning work associated with oil and gas properties owned and operated by SPN Resources at closing.
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 11%, 12% and 10% of our total revenue in 2007, 2006 and 2005, respectively. We do not believe that the loss of any one customer would have a material adverse effect on our revenues. However, our inability to continue to perform services for a number of our large existing customers, if not offset by sales to new or other existing customers, could have a material adverse effect on our business and operations.
Competition
We operate in highly competitive areas of the oilfield services industry. The products and services of each of our principal operating segments are sold in highly competitive markets, and our revenues and earnings can be affected by the following factors:
    changes in competitive prices;
 
    oil and gas prices and industry perceptions of future prices;
 
    fluctuations in the level of activity by oil and gas producers;

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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.
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 damages 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. The insurance that we are able to obtain may have higher deductibles, higher premiums, lower limits and more restrictive policy terms.
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.
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.
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 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, 2008, we had approximately 4,500 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 127 owned or leased operating facilities located in Louisiana, Texas, Alabama, Arkansas, Mississippi, Oklahoma, Colorado, New Mexico, Utah, Wyoming, Venezuela, Australia, Trinidad, Mexico, Colombia, Brazil, the United Kingdom, the Netherlands, Eastern Canada, Singapore, 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, 2007, 2006 and 2005 and estimated future net revenues and cash flows attributable thereto. Our proved reserves for 2007, 2006 and 2005 were estimated by DeGolyer and MacNaughton, independent petroleum engineers. The oil and natural reserve information contained herein does not include the reserves owned by our equity-method investee, Beryl Oil and Gas L.P. (BOG), formerly known as Coldren Resources LP.
                         
    As of December 31,
    2007   2006   2005
Total estimated net proved reserves:
                       
Oil (Mbbls)
    7,829       7,921       9,103  
Natural gas (Mmcf)
    35,260       35,641       23,688  
Total (Mboe) (1)
    13,706       13,861       13,051  
Net proved developed reserves (4):
                       
Oil (Mbbls)
    6,493       6,709       7,554  
Natural gas (Mmcf)
    34,472       28,982       21,703  
Total (Mboe) (1)
    12,238       11,539       11,171  
Estimated future net revenues before income taxes (in thousands) (2)
  $ 584,508     $ 254,600     $ 441,550  
Standardized measure of discounted future net cash flows (in thousands) (3)
  $ 359,668     $ 178,741     $ 205,105  
 
(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, 2007 amount was estimated by DeGolyer and MacNaughton using a period-end crude New York Mercantile Exchange (NYMEX) price of $95.98 per bbl for oil and a NYMEX gas price of $7.48 per million British Thermal units for natural gas, and price differentials provided by us. The December 31, 2006 amount was also estimated by DeGolyer and MacNaughton using a period-end crude 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. Net revenues as they appear in the table are defined as gross revenue, less production taxes, operating expenses, royalties 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, 2007 were 3,070 mbbls (39% of total net proved oil reserves) and 23,112 mmcf (66% of total net proved gas reserves). Net proved undeveloped reserves as of December 31, 2007 were 1,336 mbbls (17% of total net proved oil reserves) and 518 mmcf (1% 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 of productive oil and natural gas wells as of December 31, 2007. Productive wells consist of producing wells and wells capable of production. 14 gross oil wells and 5 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
    285.00       272.85  
Natural gas
    50.00       33.32  
 
               
 
               
Total
    335.00       306.17  
 
               
As of December 31, 2007, approximately 149 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.

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Acreage
The following table sets forth information as of December 31, 2007 relating to acreage held by us. Developed acreage is assigned to productive wells.
                 
    Gross     Net  
    Acreage     Acreage  
Developed
    131,550       96,535  
Undeveloped
    5,731       3,231  
 
           
 
               
Total
    137,281       99,766  
 
           
Drilling Activity
The following table shows our drilling activity for the years ended December 31, 2007, 2006 and 2005. 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.
                                                 
    2007   2006   2005
    Gross   Net   Gross   Net   Gross   Net
Development Wells:
                                               
Productive
    8.00       3.50       7.00       1.40       1.00       0.50  
Non-productive
                                   
 
                                               
 
                                               
Total
    8.00       3.50       7.00       1.40       1.00       0.50  
 
                                               
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, 2007, 2006 and 2005 (in thousands).
                         
    Years Ended December 31,  
    2007     2006     2005  
Acquisition of properties — proved
  $ 12,126     $ 45,948     $ 9,015  
Development costs
    76,928       63,396       19,867  
 
                 
 
                       
Total costs incurred
  $ 89,054     $ 109,344     $ 28,882  
 
                 
Capitalized costs for oil and gas producing activities consist of the following (in thousands):
                         
    2007     2006     2005  
Proved properties
  $ 78,344     $ 109,344     $ 28,882  
Accumulated depreciation, depletion and amortization
    (47,958 )     (26,308 )     (18,065 )
 
                 
 
                       
Capitalized costs, net
  $ 30,386     $ 83,036     $ 10,817  
 
                 

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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.
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 uncertainties 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 following:
    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.

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Our industry is highly competitive.
We compete in highly competitive areas of the oilfield services industry. The products and services of each of our principal industry segments are sold in highly competitive markets, and our revenues and earnings may be affected by the following factors:
    changes in competitive prices;
 
    fluctuations in the level of activity in major markets;
 
    an increased number of liftboats in the Gulf of Mexico;
 
    general economic conditions; and
 
    governmental regulation.
We compete with the oil and gas industry’s largest integrated and independent oilfield service providers. We believe that the principal competitive factors in the market areas that we serve are price, product and service quality, availability and technical proficiency.
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 19%, 15% and 14% of our total revenues in 2007, 2006, and 2005, respectively. Our international operations are subject to a number of risks inherent in any business operating in foreign countries including, but not limited to the following:
    political, social and economic instability;

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

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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 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. Shell accounted for approximately 11%, 12% and 10% of our total revenues in 2007, 2006, and 2005, respectively. 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 terms of our contracts could expose us to unforeseen costs and costs not within our control.
Under fixed-price contracts, turnkey or modified turnkey contracts, we agree to perform the contract for a fixed-price or a defined scope of work and extra work, which is subject to customer approval, and is billed separately. As a result, we can improve our expected profit by superior contract performance, productivity, worker safety and other factors resulting in cost savings. However, we could incur cost overruns above the approved contract price, which may not be recoverable. Prices for these contracts are established based largely upon estimates and assumptions relating to project scope and specifications, personnel and material needs. These estimates and assumptions may prove inaccurate or conditions may change due to factors out of our control, resulting in cost overruns, which we may be required to absorb and could have a material adverse effect on our business, financial condition and results of our operations. In addition, our profits from these contracts could decrease and we could experience losses if we incur difficulties in performing the contracts or are unable to secure suitable commitments from our subcontractors and other suppliers. Many of these contracts require us to satisfy specified progress milestones or performance standards in order to receive a payment. Under these types of arrangements, we may incur significant costs for equipment, labor and supplies prior to receipt of payment. If the customer fails or refuses to pay us for any reason, there is no assurance we will be able to collect amounts due to us for costs previously incurred. In some cases, we may find it necessary to terminate subcontracts and we may incur costs or penalties for canceling our commitments to them. If we are unable to collect amounts owed to us under these contracts, we may be required to record a charge against previously recognized earnings related to the project, and our liquidity, financial condition and results of operations could be adversely affected.
Percentage-of- completion accounting for contract revenue may result in material adjustments.
We expect that in 2008 an increasing portion of our revenues will be recognized using the percentage-of- completion method of accounting. The percentage-of- completion accounting practices that we use result in our recognizing contract revenues and earnings ratably over the contract term based on the proportion of actual costs incurred to our estimated contract costs. The earnings or losses recognized on individual contracts are based on estimates of contract revenues, costs and profitability. We review our estimates of contract revenues, costs and profitability on a monthly basis. Prior to contract completion, we may adjust our estimates on one or more occasions as a result of changes in cost estimates, change orders to the original contract, collection disputes with the customer on amounts invoiced or claims against the customer for extra work or increased cost due to customer-induced delays and other factors. Contract losses are recognized in the fiscal period when the loss is determined. Contract profit estimates are also adjusted in the fiscal period in which it is determined that an adjustment is required. No restatements are made to prior periods. As a result of the requirements of the percentage-of- completion method of accounting, the possibility exists, for example, that we could have estimated and reported a profit on a contract over several prior periods and later determine that all or a portion of such previously estimated and reported profits were overstated. If this occurs, the full aggregate amount of the overstatement will be reported for the period in which such determination is made,

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thereby eliminating all or a portion of any profits from other contracts that would have otherwise been reported in such period or even resulting in a loss being reported for such period.
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 the following:
    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 are $50 million per occurrence. We have a limit of $100 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.
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

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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 imposes higher deductibles and limits 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 following:
    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.
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 following:
    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

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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 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

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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, 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 Part I, Item 1 of this Form 10-K and in note 14 to our consolidated financial statements included in Part II, Item 8.
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.

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Item 4A. Executive Officers of Registrant
Terence E. Hall, age 62, 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 58, 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 53, 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 50, 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 39, 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 previously as 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.
Charles M. Hardy, age 62, was appointed as one of our Executive Vice Presidents in January 2008. He has served as Vice President and General Manager of our Marine Services division since May 2005, and previously as Vice President of Sales for this same division since August 2004. From July 2000 to July 2004, Mr. Hardy served as Vice President of Operations of Trico Marine Operators, Inc.
James A. Holleman, age 50, 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 previously 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 50, 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 52, 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.
Patrick J. Zuber, age 47, was appointed as one of our Executive Vice Presidents in January 2008. He was employed with Weatherford International, Ltd. from June 1999 to December 2007, most recently serving as Vice President for the Middle East region since January 2007. From September 2005 to December 2007, Mr. Zuber served as Vice President for the Asia Pacific region. From March 2002 to August 2005, he served as General Manager for the Underbalanced Drilling Division for the Middle East and North Africa region.

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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
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  
 
               
2007
               
First Quarter
  $ 36.15     $ 28.20  
Second Quarter
    41.78       34.35  
Third Quarter
    41.92       34.25  
Fourth Quarter
    37.95       31.57  
As of February 18, 2008, there were 80,775,931, shares of our common stock outstanding, which were held by 207 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 our common stock repurchased and retired during the year ended December 31, 2007 in connection with our $350 million share repurchase program that will expire on December 31, 2009:
                                 
                            Approximate
                    Total Number of   Dollar Value of
                    Shares   Shares that May
    Total Number of           Purchased as   Yet be
    Shares   Average Price   Part of Publicly   Purchased
Period   Purchased   Paid per Share   Announced Plan   Under the Plan
October 2007
    1,000,000     $ 33.77       1,000,000     $ 316,200,000  

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Performance Graph
The following performance graph and related information shall not be deemed “solicitating material” or “filed” with the Securities and Exchange Commission, nor shall such information be incorporated by reference into any future filing under the Securities Exchange Act of 1933 or Securities Exchange Act of 1934, except to the extent that the Company specifically incorporates it by reference into such filing.
The following graph compares the total stockholder return on our common stock for the last five years with the total return on the S&P 500 Stock 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, 2003 at closing prices on December 31, 2002.
The comparisons in the graph are required by the Securities and Exchange Commission and are not intended to be a forecast or be indicative of possible future performance of our common stock.
(PERFORMANCE GRAPH)
                                                                 
 
        Years Ended December 31,  
        2002     2003     2004     2005     2006     2007  
 
Superior Energy Services, Inc.
    $ 100       $ 115       $ 188       $ 257       $ 399       $ 420    
 
S&P 500 Stock Index
    $ 100       $ 129       $ 143       $ 150       $ 173       $ 183    
 
Peer Group
    $ 100       $ 109       $ 146       $ 222       $ 231       $ 311    
 
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.

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    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, 2002.
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.
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,
    2007   2006   2005   2004   2003
Revenues
  $ 1,572,467     $ 1,093,821     $ 735,334     $ 564,339     $ 500,625  
Income from operations
    465,838       316,889       125,603       76,289       67,343  
Net income
    281,120       188,241       67,859       35,852       30,514  
Net income per share:
                                       
Basic
    3.47       2.36       0.87       0.48       0.41  
Diluted
    3.41       2.32       0.85       0.47       0.41  
Total assets
    2,257,249       1,874,478       1,097,250       1,003,913       832,863  
Long-term debt, less current portion
    711,151       711,505       216,596       244,906       255,516  
Decommissioning liabilities, less current portion
    88,158       87,046       107,641       90,430       18,756  
Stockholders’ equity
    980,679       710,688       524,374       433,879       368,129  

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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, including those disclosed in Part I, Item 1A. The following information contains forward-looking statements, which are subject to risks and uncertainties. Should one or more of these risks or uncertainties materialize, our actual results may differ from those expressed or implied by the forward-looking statements. See “Forward-Looking Statements” at the beginning of this Annual Report on Form 10-K.
Executive Summary
We are a leading provider of oilfield services and equipment focused on serving the drilling-related needs of oil and gas companies primarily through our rental tools segment, and the production-related needs of oil and gas companies through our well intervention, rental tools and marine segments. In recent years, we have expanded geographically into 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 financial performance of our various products and services are reported in four different segments – well intervention, rental tools, marine and oil and gas.
In February 2008, we entered into a purchase agreement to sell 75% of our interest in SPN Resources for approximately $165 million in cash, subject to certain conditions. The transaction is expected to close during the first quarter of 2008. We will retain the preferential rights on all service work and have agreed to perform, on a fixed price basis, the decommissioning work associated with oil and gas properties owned and operated by SPN Resources at closing.
Overview of our business segments
The well intervention segment consists of specialized down-hole services, which are both labor and equipment intensive. We offer a wide variety of services used to maintain, enhance and extend oil and gas production from mature wells. Four services – coiled tubing, electric line, hydraulic workover/snubbing and well control – each account for more than 10% of this segment’s revenue. While our gross margin percentage tends to be fairly consistent, special projects such as well control can directly increase the gross margin.
The rental tools segment is capital intensive with high margins as a result of relatively low operating costs. The largest fixed cost is depreciation as there is little labor associated with our rental tools businesses. The financial performance primarily is a function of changes in volume rather than pricing. Three rental products and their ancillary equipment – accommodations, drill pipe and stabilization tools – each account for more than 20% of this segment’s revenue.
The marine segment is comprised of our 27 rental liftboats. Operating costs of our liftboats are relatively fixed, and therefore, gross margin percentages vary significantly from quarter-to-quarter and year-to-year based on changes in dayrates and utilization levels. As an indication of this segment’s performance, gross margin for 2007 was 53% as compared to 60% in 2006 primarily due to decreases in dayrates and utilization across several of our liftboat classes.
Through our subsidiary SPN Resources, LLC, we acquire, manage and decommission mature properties on the Outer Continental Shelf of the Gulf of Mexico. As of December 31, 2007, we had interests in 31 offshore blocks containing 79 structures and approximately 149 producing wells. The main objective of this business segment is to provide additional opportunities for our products and services in the Gulf of Mexico, especially during cyclical and seasonal slower periods. Because of the fixed cost nature of our well intervention services, the incremental cost to work on mature properties is far less than it would be for traditional energy producers. This segment provides work for our Gulf of Mexico-based services, thereby increasing utilization of our own assets by deploying services on our own properties during periods of downtime.
The lease operating expenses for these types of properties are typically high because of the amount of well intervention service work required to enhance, maintain and extend production for mature properties. The gross margin is also a function of the age of these oil and gas properties.

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Market drivers and conditions
The oil and gas industry remains highly cyclical and seasonal. Activity levels in our well intervention, marine and rental tools segments are driven primarily by traditional energy industry activity indicators, which include current and expected commodity prices, drilling rig counts, well completions and workover activity, geological characteristics of producing wells which determine the number of services required per well, oil and gas production levels, and customers’ spending allocated for drilling and production work, which is reflected in our customers’ operating expenses or capital expenditures.
Historical market indicators are listed below:
                                         
            %           %    
    2007   Change   2006   Change   2005
Worldwide Rig Count (1)
                                       
U.S.
    1,768       7 %     1,648       19 %     1,380  
International (2)
    1,005       9 %     925       2 %     908  
Commodity Prices (average)
                                       
Crude Oil (West Texas Intermediate)
  $ 72.19       9 %   $ 66.43       17 %   $ 56.82  
Natural Gas (Henry Hub)
  $ 8.67       21 %   $ 7.17       -21 %   $ 9.06  
 
(1)   Estimate of drilling activity as measured by average active drilling rigs based on Baker Hughes Inc. rig count information.
 
(2)   Excludes Canada Rig Count
Factors impacting our 2007 financial performance
Several factors contributed to our financial performance in 2007. First, we continued to execute our long-term growth strategy of expanding geographically in an effort to reduce our dependency on a single geographic region, especially the Gulf of Mexico. As evidence of our successful execution of the diversification strategy, our non-Gulf of Mexico revenue was a record approximate $803 million, or 51% of our 2007 total revenue, as compared to approximately $439 million, or 40% of 2006 total revenue. Second, we experienced a significant increase in revenue from our domestic land markets, primarily due to acquisitions and capital expenditures. Third, average oil and natural gas prices increased over 2006 averages, which positively impacted customer spending as well as our financial performance in our oil and gas segment. Fourth, the average number of rigs drilling for oil and natural gas in domestic and international market areas increased 8% over 2006, which directly impacts demand for most of our rental tools and serves as a proxy for customer spending and activity levels on well intervention services. Fifth, we experienced a decrease in demand for liftboats and certain well intervention services in the Gulf of Mexico as construction, plug and abandonment, and other well intervention activity returned to more normal levels following a period of unprecedented demand in the aftermath of Hurricanes Katrina and Rita, which caused significant damage to oil and gas infrastructure in the Gulf of Mexico during the third quarter of 2005. Although significant work remains to remove downed and damaged platforms, the immediate needs of the industry to restore production have been largely met.
Geographically, our largest increase in revenue was from domestic land markets, which was approximately $504 million, or 32% of total revenue, as compared to approximately $270 million, or 25% of our total revenue in 2006. The two primary factors leading to this growth were acquisitions and capital expenditures. Starting with our acquisition of Warrior Energy Services, Inc. in December 2006, we made four acquisitions through December 31, 2007 of businesses with significant exposure to certain domestic land market areas. Warrior Energy Services, which was the largest of these acquisitions, continued an aggressive growth strategy in which it spent approximately $74 million to purchase coiled tubing spreads and electric line spreads. These acquisitions and subsequent capital expenditures contributed approximately $180 million in domestic land revenue in 2007.
International revenue was approximately $299 million, or 19% of total revenue, as compared to approximately $169 million, or 15% of total revenue in 2006. The primary reasons for the increase were an approximate $69 million increase in international revenue from our rental tools segment as a result of an increase in the international drilling rig count and our capital expenditures. In addition, international revenue from our well intervention segment

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increased from approximately $73 million to approximately $135 million in 2007 due primarily to our derrick barge charter and construction contracts and additional revenue from two of our core businesses — well control and hydraulic workover / snubbing.
Gulf of Mexico revenue was approximately $769 million or 49% of total revenue, as compared to $655 million, or 60% of total revenue in 2006. Gulf of Mexico revenue from our well intervention, rental tools and oil and gas segments increased approximately $125 million, which offset an approximate decrease of $11 million from the marine segment. Well intervention revenue from the Gulf of Mexico increased approximately $37 million, or 14% to approximately $303 million, primarily related to increases in hydraulic workover, snubbing and well control activity. Rental tools revenue from the Gulf of Mexico increased approximately $15 million, or 11% to approximately $152 million, as a result of increases in deepwater drilling activity, which lead to increases in drill pipe rentals. In addition, rentals of stabilizers, drill collars and connecting iron also increased.
Oil and gas revenue increased approximately $65 million, or 51% due to a 32% increase in barrels of oil and gas equivalent (boe) produced as well as a 7% increase in average realized prices. In 2006, shut-in production resulting from damage caused by the 2005 hurricane season did not fully return until the second quarter of 2006.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations are based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Note 1 to our 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

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assets not previously recorded. We test goodwill for impairment in accordance with Statement of Financial Accounting Standards No. 142 (FAS No. 142), “Goodwill and Other Intangible Assets.” FAS No. 142 requires that goodwill as well as other intangible assets with indefinite lives no longer be amortized, but instead tested annually for impairment. Our annual testing of goodwill is based on our fair value and carrying value at December 31. We estimate the fair value of each of our reporting units (which are consistent with our reportable segments) using various cash flow and earnings projections. We then compare these fair value estimates to the carrying value of our reporting units. If the fair value of the reporting units exceeds the carrying amount, no impairment loss is recognized. Our estimates of the fair value of these reporting units represent our best estimates based on industry trends and reference to market transactions. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events.
Income Taxes. We provide for income taxes in accordance with Statement of Financial Accounting Standards No. 109 (FAS No. 109), “Accounting for Income Taxes.” This standard takes into account the differences between financial statement treatment and tax treatment of certain transactions. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Our deferred tax calculation requires us to make certain estimates about our future operations. Changes in state, federal and foreign tax laws, as well as changes in our financial condition or the carrying value of existing assets and liabilities, could affect these estimates. The effect of a change in tax rates is recognized as income or expense in the period that includes the enactment date.
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. Our products and services are generally sold based upon purchase orders or contracts with customers that include fixed or determinable prices. We recognize revenue when services or equipment are provided and collectibility is reasonably assured. 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, third party liability insurances, property damage, and group medical. With the growth of the Company, we have elected to retain more risk by increasing our self-insurance. We accrue for these liabilities based on estimates of the ultimate cost of claims incurred as of the balance sheet date. We regularly review our estimates of reported and unreported claims and provide for losses through reserves. We also have actuarial reviews 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

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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 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 cannot 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, 2007 and 2006
For the year ended December 31, 2007, our revenues were $1,572.5 million, resulting in net income of $281.1 million or $3.41 diluted earnings per share. Our net income includes a pre-tax gain of $7.5 million from the sale of a non-core rental tool business. For the year ended December 31, 2006, revenues were $1,093.8 million, and net income was $188.2 million or $2.32 diluted earnings per share. Net income for the year ended December 31, 2006 includes a pre-tax loss on early extinguishment of debt of $12.6 million. Revenue and gross margin were higher in the well intervention and rental tools segments as a result of increased production-related projects and drilling activity worldwide, recent acquisitions and continued expansion of our rental tool business. Both revenue and gross margin decreased in our marine segment due to lower utilization. Both revenue and gross margin in our oil and gas segment were significantly higher due to higher commodity prices and higher production as a portion of 2006 production was impacted by shut-in production due to Hurricanes Katrina and Rita.

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The following table compares our operating results for the years ended December 31, 2007 and 2006. 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  
    2007     2006     Change     2007            %   2006            %   Change  
         
Well Intervention
  $ 761,015     $ 469,110     $ 291,905     $ 341,197       45 %   $ 199,479       43 %   $ 141,718  
Rental Tools
    496,290       371,155       125,135       339,559       68 %     255,257       69 %     84,302  
Marine
    127,898       140,115       (12,217 )     67,466       53 %     83,926       60 %     (16,460 )
Oil and Gas
    192,700       127,682       65,018       126,120       65 %     57,654       45 %     68,466  
Less: Oil and Gas Elim.
    (5,436 )     (14,241 )     8,805                                
                                       
 
                                                               
Total
  $ 1,572,467     $ 1,093,821     $ 478,646     $ 874,342       56 %   $ 596,316       55 %   $ 278,026  
                                           
The following discussion analyzes our results on a segment basis.
Well Intervention Segment
Revenue for our well intervention segment was $761.0 million for the year ended December 31, 2007, as compared to $469.1 million for 2006. This segment’s gross margin percentage increased to 45% in 2007 from 43% in 2006. We experienced higher revenue for most of our production-related services. Approximately 60% of our increase in revenue is attributable to acquisition and disposition activities occurring late in 2006 and throughout 2007. An additional 20% of the increase in revenue is from a full year of activity related to the charter of a derrick barge as well as a contract to construct a derrick barge to be sold to a third party for approximately $53 million. The balance of the increase in revenue is attributable to increased well control and hydraulic workover services as production-related activity improved.
Rental Tools Segment
Revenue for our rental tools segment for 2007 was $496.3 million, a 34% increase over 2006. The gross margin percentage remained relatively constant at 68% in 2007 as compared to 69% in 2006. In 2007, we sold the assets of a non-core rental business. We experienced significant increases in revenue from our stabilizers, on-site accommodations, drill pipe and accessories, and drill collars. The increases are a result of recent acquisitions, expansion of rental products through capital expenditures, and increased activity worldwide. Our international revenue for the rental tools segment has increased 73% to approximately $163 million in 2007 over 2006. Our largest improvements were in the North Sea, South America and Africa market areas.
Marine Segment
Our marine segment revenue for the year ended December 31, 2007 decreased 9% from 2006 to $127.9 million. Likewise, gross margin for 2007 experienced a decrease of 20% from 2006 due to lower utilization. Due to the high fixed costs associated with this segment, gross margin decreases at an accelerated rate when revenue declines. The fleet’s average utilization decreased to approximately 71% in 2007 from 82% in 2006 due to increased idle days resulting from lower demand, inspections, maintenance and poor weather conditions in the Gulf of Mexico which prevent our liftboats from mobilizing in high seas. The fleet’s average dayrate increased approximately 4% to approximately $17,300 in 2007 from $16,600 in 2006.
Oil and Gas Segment
Oil and gas revenues were $192.7 million in the year ended December 31, 2007, as compared to $127.7 million in 2006. In 2007, production was approximately 3,305,000 boe, as compared to approximately 2,505,000 boe in 2006. The gross margin percentage increased to 65% in 2007 from 45% in 2006 due to increased production and commodity prices. In 2006, shut-in production resulting from damage caused by the 2005 hurricane season did not fully return until the second quarter of 2006.

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Depreciation, Depletion, Amortization and Accretion
Depreciation, depletion, amortization and accretion increased to $187.8 million in the year ended December 31, 2007 from $111.0 million in 2006. Approximately 40% of our increase in depreciation and amortization expense is attributable to acquisitions occurring late in 2006 and throughout 2007. An additional 36% increase in depletion and accretion is directly attributable to increased oil and gas production and capital expenditures in our oil and gas segment. The balance of the increase results from the depreciation associated with our 2007 and 2006 capital expenditures, primarily in the well intervention and rental tools segment.
General and Administrative Expenses
General and administrative expenses increased to $228.1 million for the year ended December 31, 2007 from $168.4 million in 2006. Approximately 50% of our increase in general and administrative expenses is attributable to acquisitions occurring late in 2006 and throughout 2007. The remainder of 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 14.5% of revenue for 2007 from 15.4% in 2006.
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 pre-tax 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.
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 activity levels increased significantly due to increased demand for production-related services and hurricane-related repair work in the Gulf of Mexico. As a measure of increased activity, our plug and abandonment crew count increased by approximately 49% over 2005 and our offshore mechanical wireline job count increased by approximately 11%. We also increased our

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revenues in domestic onshore markets and acquired Warrior Energy Services Corporation in December 2006 to further this expansion and strengthen this segment. Our mechanical wireline job count increased approximately 9% in domestic land market areas.
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 rental revenue in the Gulf of Mexico increased 51% to approximately $136 million. Similarly, rental revenue from domestic land markets also increased significantly, 43%, to approximately $140 million. 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. Approximately 50% of the total increase is related to depletion and accretion directly attributable to increased oil and gas production. The balance of the increase results from the depreciation associated with our 2006 and 2005 capital expenditures, primarily in the rental tools segment.
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 15.4% of revenue for 2006 from 19.2% in 2005.
Liquidity and Capital Resources
In the year ended December 31, 2007, we generated net cash from operating activities of $530.5 million as compared to $280.2 million in 2006. 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

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under our revolving credit facility. We had cash and cash equivalents of $51.6 million at December 31, 2007 compared to $39.0 million at December 31, 2006.
We made approximately $410.5 million of capital expenditures during the year ended December 31, 2007, of which approximately $162.6 million was used to expand and maintain our rental tool equipment inventory. We also made $75.7 million of capital expenditures in our oil and gas segment and $155.5 million of capital expenditures to expand and maintain the asset base of our well intervention and marine segments. In addition, we made $16.7 million of capital expenditures on construction and improvements to our facilities.
In January 2007, we acquired Duffy & McGovern Accommodation Services Limited, a provider of offshore accommodation rentals operating in most deep water oil and gas territories with major operations in Europe, Africa, the Americas and South East Asia, for approximately $47.5 million in cash consideration. In April 2007, we also acquired Advanced Oilwell Services, Inc., a provider of cementing and pressure pumping services primarily operating in the East Texas region, for approximately $24.2 million in cash consideration. In August 2007, we sold the assets of a non-core rental tool business for approximately $16.3 million in cash and $2.0 million in a note receivable.
We have a $250 million bank revolving credit facility. Any amounts outstanding under the revolving credit facility are due on June 14, 2011. At February 18, 2008, no amounts were outstanding under the bank credit facility, but we had approximately $98.6 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 $15.8 million outstanding at December 31, 2007 in U. S. Government guaranteed long-term financing under Title XI of the Merchant Marine Act of 1936, which is administered by the Maritime Administration (MARAD), for two 245-foot class liftboats. This debt bears an interest rate of 6.45% per annum and is payable in equal semi-annual installments of $405,000 on every June 3rd and December 3rd through June 3, 2027. Our obligations are secured by mortgages on the two liftboats. This MARAD financing also requires that we comply with certain covenants and restrictions, including the maintenance of minimum net worth and debt-to-equity requirements.
We have $300 million of 6 7/8% unsecured senior notes due 2014. 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.
We also have $400 million of 1.50% senior exchangeable notes due 2026. The exchangeable 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 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;

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    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 October 2007, we repurchased and retired 1,000,000 shares of our outstanding common stock at an average price of $33.77 per share, or approximately $33.8 million in the aggregate, in connection with our $350 million share repurchase program that will expire on December 31, 2009.
The following table summarizes our contractual cash obligations and commercial commitments at December 31, 2007 (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 $30.2 million, when decommissioning operations are performed. The vessel construction obligation amounts do not give any effect to our contractual right to receive payments from a third-party customer, which is approximately $3.1 million. We do not have any other material obligations or commitments.
                                                 
Description   2008     2009     2010     2011     2012     Thereafter  
 
Long-term debt, including estimated interest payments
  $ 28,440     $ 28,388     $ 28,336     $ 27,783     $ 27,231     $ 818,347  
Decommissioning liabilities
    36,812       2,475       10,668       29,992       6,659       38,364  
Operating leases
    14,800       7,167       4,018       2,774       1,221       15,253  
Vessel Construction
    39,750                                
     
Total
  $ 119,802     $ 38,030     $ 43,022     $ 60,549     $ 35,111     $ 871,964  
               
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, 2007, the maximum additional consideration payable for our prior acquisitions was approximately $29.5 million. These amounts are not classified as liabilities under current 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 $437 million of capital expenditures, excluding acquisitions and targeted asset purchases, during 2008 to expand our rental tool asset base, add new coiled tubing and electric-line units, complete construction on our derrick barge and perform workovers on SPN Resources’ oil and gas properties. We believe that our current working capital, cash generated from our operations and availability under our revolving credit facility will provide sufficient funds for our identified capital projects.

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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 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 applies under other accounting pronouncements that require or permit fair value measurements. FAS No. 157 indicates, among other things, a fair value measurement assumes that the transaction to sell an asset or transfer a liability occurs in the principal market for the asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability. 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 February 2007, the Financial Accounting Standards Board issued its Statement of Financial Accounting Standards No. 159 (FAS No. 159), “The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115,” which is effective for fiscal years beginning after November 15, 2007. This statement permits an entity to choose to measure many financial instruments and certain other items at fair value at specified election dates. Subsequent unrealized gains and losses on items for which the fair value option has been elected will be reported in earnings. We believe the adoption of FAS No. 159 will not have a material impact on our results of operations and financial position.
In December 2007, the Financial Accounting Standards Board issued its Statement of Financial Accounting Standards No. 141(R) (FAS No. 141(R)), “Business Combinations (as amended).” FAS No. 141(R) requires an acquiring entity in a business combination to recognize all assets acquired and liabilities assumed in the transaction and any noncontrolling interest in the acquiree at the acquisition date fair value. Additionally, contingent consideration and contractual contingencies shall be measured at acquisition date fair value. FAS No. 141(R) also requires an acquirer to disclose all of the information users may need to evaluate and understand the nature and financial effect of the business combination. Such information includes, among other things, a description of the factors comprising goodwill recognized in the transaction, the acquisition date fair value of the consideration, including contingent consideration, amounts recognized at the acquisition date for each major class of assets acquired and liabilities assumed, transactions not considered to be part of the business combination (i.e., separate transactions), and acquisition-related costs. FAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 (for any acquisitions closed on or after January 1, 2009 for the Company), and early adoption is not permitted. While we do not expect the adoption of FAS No. 141(R) to have a material impact on our results of operations and financial position for transactions completed prior to December 31, 2008, the impact of the accounting change could be material for acquisitions closed on or after January 1, 2009.

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In December 2007, the Financial Accounting Standards Board issued its Statement of Financial Accounting Standards No. 160 (FAS No. 160), “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51.” FAS No. 160 amends ARB No. 51 to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. Additionally, this statement requires that consolidated net income include the amounts attributable to both the parent and the noncontrolling interest. FAS No. 160 is effective for fiscal years beginning on or after December 15, 2008. We are currently evaluating the impact that FAS No. 160 will have on our results of operations and 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 and the Netherlands, 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 subsidiaries in the United Kingdom and the Netherlands 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, 2007, none of our outstanding long-term debt 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 occurrence 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 135% of the applicable exchange rate 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 ownership or structure, the holders may require us to repurchase all or any portion of the notes for 100% of the principal amount.

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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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” in Part II, Item 7.
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 have used 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, 2007 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, and for performing an assessment of the effectiveness of internal control over our financial reporting as of December 31, 2007. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Our system of internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the financial statements.
Our management, including our principal executive officer and principal financial officer, performed an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2007 based upon criteria in “Internal Control – Integrated Framework,” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment under the criteria in “Internal Control – Integrated Framework,” our management determined that our internal control over financial reporting was effective as of December 31, 2007.
Our internal control over financial reporting as of December 31, 2007 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which appears herein.

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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, 2007 and 2006, 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, 2007. In connection with our audits of the consolidated financial statements, we also have audited the accompanying financial statement schedule, “Valuation and Qualifying Accounts” for the years ended December 31, 2007, 2006, and 2005. 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, 2007 and 2006, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2007, 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, present fairly, in all material respects, the information set forth therein.
Effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 123 (R), Share-Based Payment.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Superior Energy Services, Inc.’s internal control over financial reporting as of December 31, 2007, 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, 2008 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
          KPMG LLP
New Orleans, Louisiana
February 28, 2008

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Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Superior Energy Services, Inc.:
We have audited Superior Energy Services, Inc.’s internal control over financial reporting as of December 31, 2007, 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, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on 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, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included 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, Superior Energy Services, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
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. as of December 31, 2007 and 2006, 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, 2007, and our report dated February 28, 2008 expressed an unqualified opinion on those consolidated financial statements.
          KPMG, LLP
New Orleans, Louisiana
February 28, 2008

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Balance Sheets
December 31, 2007 and 2006
(in thousands, except share data)
                 
    2007     2006  
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 51,649     $ 38,970  
Accounts receivable, net of allowance for doubtful accounts of $16,742 and $17,419 at December 31, 2007 and 2006, respectively
    343,334       303,800  
Income taxes receivable
          2,630  
Current portion of notes receivable
    15,584       14,824  
Prepaid expenses
    19,641       17,782  
Other current assets
    40,797       41,781  
 
           
Total current assets
    471,005       419,787  
 
           
Property, plant and equipment, net
    878,352       626,558  
Oil and gas assets, net, under the successful efforts method of accounting
    208,056       177,670  
Goodwill
    484,594       444,687  
Notes receivable
    16,732       16,137  
Equity-method investments
    56,961       64,603  
Intangible and other long-term assets, net
    141,549       125,036  
 
           
Total assets
  $ 2,257,249     $ 1,874,478  
 
           
 
               
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
Current liabilities:
               
Accounts payable
  $ 69,510     $ 65,451  
Accrued expenses
    177,779       137,164  
Income taxes payable
    7,520        
Current portion of decommissioning liabilities
    36,812       35,150  
Current maturities of long-term debt
    810       810  
 
           
Total current liabilities
    292,431       238,575  
 
           
Deferred income taxes
    163,338       112,011  
Decommissioning liabilities
    88,158       87,046  
Long-term debt
    711,151       711,505  
Other long-term liabilities
    21,492       14,653  
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 80,671,650 and 80,617,337 shares at December 31, 2007 and 2006, respectively
    81       81  
Additional paid in capital
    401,455       411,374  
Accumulated other comprehensive income, net
    9,078       10,288  
Retained earnings
    570,065       288,945  
 
           
Total stockholders’ equity
    980,679       710,688  
 
           
Total liabilities and stockholders’ equity
  $ 2,257,249     $ 1,874,478  
 
           
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, 2007, 2006 and 2005
(in thousands, except per share data)
                         
    2007     2006     2005  
Oilfield service and rental revenues
  $ 1,379,767     $ 966,139     $ 656,423  
Oil and gas revenues
    192,700       127,682       78,911  
 
                 
Total revenues
    1,572,467       1,093,821       735,334  
 
                 
Cost of oilfield services and rentals
    631,545       427,477       330,200  
Cost of oil and gas sales
    66,580       70,028       45,804  
 
                 
Total cost of services, rentals and sales
    698,125       497,505       376,004  
 
                 
Depreciation, depletion, amortization and accretion
    187,841       111,011       89,288  
General and administrative expenses
    228,146       168,416       140,989  
Reduction in value of assets
                6,994  
Gain on sale business
    7,483             3,544  
 
                 
Income from operations
    465,838       316,889       125,603  
 
                 
Other income (expense):
                       
Interest expense, net of amounts capitalized
    (33,257 )     (22,950 )     (21,862 )
Interest income
    2,851       4,612       2,201  
Loss on early extinguishment of debt
          (12,596 )      
Earnings (losses) from equity-method investments
    (2,940 )     5,891       1,339  
Reduction in value of equity-method investment
                (1,250 )
 
                 
Income before income taxes
    432,492       291,846       106,031  
Income taxes
    151,372       103,605       38,172  
 
                 
Net income
  $ 281,120     $ 188,241     $ 67,859  
 
                 
 
                       
Basic earnings per share
  $ 3.47     $ 2.36     $ 0.87  
 
                 
 
                       
Diluted earnings per share
  $ 3.41     $ 2.32     $ 0.85  
 
                 
 
                       
Weighted average common shares used in computing earnings per share:
                       
Basic
    80,973       79,801       78,321  
Incremental common shares from stock options
    1,358       1,451       1,394  
Incremental common shares from restricted stock units
    58       37       20  
 
                 
Diluted
    82,389       81,289       79,735  
 
                 
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, 2007, 2006 and 2005
(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, 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 )           (5,138 )
Foreign currency translation adjustment
                                  (2,662 )           (2,662 )
     
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  
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 Changes in Stockholders’ Equity (Continued)
Years Ended December 31, 2007, 2006 and 2005
(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, 2006
        $       80,617,337     $ 81     $ 411,374     $ 10,288     $ 288,945     $ 710,688  
Comprehensive income:
                                                               
Net income
                                        281,120       281,120  
Other comprehensive income - Changes in fair value of equity-method hedging positions, net of tax
                                  (2,580 )           (2,580 )
Foreign currency translation adjustment
                                  1,370             1,370  
     
Total comprehensive income
                                  (1,210 )     281,120       279,910  
Grant of restricted stock units
                            840                   840  
Grant of restricted stock, net of forfeitures
                160,234             2,685                   2,685  
Exercise of stock options
                867,916       1       8,439                   8,440  
Tax benefit from stock options
                            9,408                   9,408  
Stock option compensation expense
                            1,529                   1,529  
Shares issued under Employee Stock Purchase Plan
                26,163             949                   949  
Shares repurchased and retired
                (1,000,000 )     (1 )     (33,769 )                 (33,770 )
     
Balances, December 31, 2007
        $       80,671,650     $ 81     $ 401,455     $ 9,078     $ 570,065     $ 980,679  
     
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, 2007, 2006 and 2005
(in thousands)
                         
    2007     2006     2005  
Cash flows from operating activities:
                       
Net income
  $ 281,120     $ 188,241     $ 67,859  
Adjustments to reconcile net income to net cash provided by operating activities:
                       
Depreciation, depletion, amortization and accretion
    187,841       111,011       89,288  
Deferred income taxes
    61,774       15,663       442  
Stock-based and performance share unit compensation expense
    12,549       6,159       1,404  
Reduction in value of assets and equity-method investment
                8,244  
(Earnings) losses from equity-method investments
    2,940       (5,891 )     (1,339 )
Write-off of debt acquisition costs
          2,817        
Amortization of debt acquisition costs and note discount
    3,518       1,321       1,127  
Gain on sale of business
    (7,483 )           (3,544 )
Changes in operating assets and liabilities, net of acquisitions and dispositions:
                       
Receivables
    (25,361 )     (88,298 )     (32,095 )
Accounts payable
    (7,036 )     7,259       5,696  
Accrued expenses
    7,591       43,379       15,530  
Decommissioning liabilities
    (2,769 )     (2,255 )     (8,772 )
Income taxes
    8,524       (13,084 )     26,137  
Other, net
    7,264       13,892       (11,598 )
 
                 
Net cash provided by operating activities
    530,472       280,214       158,379  
 
                 
 
                       
Cash flows from investing activities:
                       
Payments for capital expenditures
    (410,518 )     (242,936 )     (125,166 )
Acquisitions of businesses, net of cash acquired
    (110,973 )     (239,339 )     (6,435 )
Acquisitions of oil and gas properties, net of cash acquired
    (8,000 )     (46,631 )     3,686  
Cash proceeds from sale of business, net of cash sold
    18,100       18,343       19,588  
Cash contributed to equity-method investment
          (57,781 )      
Cash proceeds from sale of equity-method investment
                12,489  
Other
    9,091       (13,634 )     (1,097 )
 
                 
Net cash used in investing activities
    (502,300 )     (581,978 )     (96,935 )
 
                 
Cash flows from financing activities:
                       
Proceeds from long-term debt
          695,467        
Principal payments on long-term debt
    (810 )     (200,810 )     (39,310 )
Payment of debt acquisition costs
    (83 )     (18,357 )     (439 )
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
    8,440       2,803       18,161  
Tax benefit from exercise of stock options
    9,408       1,429        
Proceeds from issuance of stock through employee benefit plans
    806              
Purchase and retirement of stock
    (33,770 )     (159,999 )      
 
                 
 
                       
Net cash provided by (used in) financing activities
    (16,009 )     284,933       (21,588 )
 
                 
Effect of exchange rate changes in cash
    516       1,344       (680 )
 
                 
Net increase (decrease) in cash and cash equivalents
    12,679       (15,487 )     39,176  
Cash and cash equivalents at beginning of year
    38,970       54,457       15,281  
 
                 
Cash and cash equivalents at end of year
  $ 51,649     $ 38,970     $ 54,457  
 
                 
See accompanying notes to consolidated financial statements.

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2007, 2006 and 2005
(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 2007 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 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 (see note 19).
 
  (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 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 2007, 2006 and 2005, Shell accounted for approximately 11%, 12% and 10%, respectively, of total revenue, primarily related to our oil and gas and rental tools segments. The Company’s inability to continue to perform services for a number of large existing customers, if not offset by sales to new or existing customers, could have a material adverse effect on the Company’s business and financial condition.

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  (e)   Cash Equivalents
 
      The Company considers all short-term investments with a maturity of 90 days or less to be cash equivalents.
 
  (f)   Accounts Receivable and Allowances
 
      Trade accounts receivable 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 probable uncollectible amounts in existing accounts receivable. The Company determines the allowance based on historical write-off experience and specific identification.
 
  (g)   Other Current Assets
 
      Other current assets include approximately $26.9 million and $14.7 million of raw materials and supplies at December 31, 2007 and 2006, respectively. Raw materials and supplies consist principally of products which are consumed in our services provided to customers, spare parts and supplies for equipment used in providing these services, and raw materials used for finished products. These supplies are stated at the lower of cost or market. Cost primarily represents invoiced costs. Cost is determined on an average cost basis for all other raw materials and supplies.
 
  (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. The Company capitalized approximately $1.5 million, $0.9 million and $0.5 million in 2007, 2006 and 2005, respectively, of interest for various capital projects.
 
      Long-lived assets and certain identifiable intangibles are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the 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 values of the reporting units exceeded the carrying amounts. No impairment loss was recognized in the years ended December 31, 2007, 2006 or 2005 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 $29.0 million in 2007 as a result of the Company’s business acquisition and disposition activity during the year. Goodwill also increased approximately $9.6 million related to the 2006 acquisition of Warrior Energy Services Corporation as the Company finalized the initial valuation of the acquired assets and liabilities. Additionally, goodwill increased in 2007 by approximately $0.7 million as the result of changes in foreign currency exchange rates and approximately $0.6 million as a result of additional consideration paid for a prior acquisition. Goodwill has been allocated to the Company’s reportable segments as follows: $329.7 million to the well intervention segment; $143.7 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.

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(k)   Intangible and Other Long-Term Assets
 
    Intangible and other long-term assets consist of the following at December 31, 2007 and 2006 (amounts in thousands):
                                                 
    December 31, 2007     December 31, 2006  
    Gross     Accumulated     Net     Gross     Accumulated     Net  
    Amount     Amortization     Balance     Amount     Amortization     Balance  
Customer relationships
  $ 108,561     $ (7,024 )   $ 101,537     $ 88,360     $ (451 )   $ 87,909  
Tradenames
    15,766       (896 )     14,870       12,788       (116 )     12,672  
Non-compete agreements
    1,375       (457 )     918       500       (70 )     430  
Debt acquisition costs
    19,896       (3,572 )     16,324       19,813       (378 )     19,435  
Deferred compensation plan assets
    7,611             7,611       4,265             4,265  
Other
    481       (192 )     289       444       (119 )     325  
 
                                   
 
                                               
Total
  $ 153,690     $ (12,141 )   $ 141,549     $ 126,170     $ (1,134 )   $ 125,036  
 
                                   
    Customer relationships, tradenames, and non-compete agreements are amortized using the straight-line method over the life of the related asset with weighted average useful lives of 15 years, 18 years, and 3 years, respectively. Debt acquisition costs are amortized primarily using the effective interest method over the life of the related debt agreements with a weighted average useful life of 7 years. Amortization expense was approximately $7.8 million, $0.6 million, and $0.3 million for the years ended December 31, 2007, 2006 and 2005, respectively. Estimated annual amortization will be approximately $9 million for each of the next five years, excluding the effects of any acquisitions or dispositions subsequent to December 31, 2007.
 
(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

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    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 years ended December 31, 2007 and 2006 (amounts in thousands):
                 
    Year Ended December 31,  
    2007     2006  
Decommissioning liabilities, beginning of period
  $ 122,196     $ 121,909  
Liabilities acquired and incurred
    300       3,554  
Liabilities settled
    (2,769 )     (2,255 )
Accretion
    4,438       4,866  
Revision in estimated liabilities
    805       (5,878 )
 
           
Total decommissioning liabilities, end of period
    124,970       122,196  
Less: current portion
    36,812       35,150  
 
           
Decommissioning liabilities
  $ 88,158     $ 87,046  
 
           
(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)   Taxes Collected from Customers
 
    Pursuant to Emerging Issues Task Force Issue No. 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement”, the Company elected to net taxes collected from customers against those remitted to government authorities in the financial statements consistent with the historical presentation of this information.
 
(o)   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.
 
(p)   Earnings per Share
 
    Basic earnings per share is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share is computed in the same manner as basic earnings per share except that the denominator is increased to include the number of additional common shares that could have been outstanding assuming the exercise of stock options and restricted stock units and the potential shares that would have a dilutive effect on earnings per share.

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    In connection with the Company’s outstanding senior exchangeable notes, there could be a dilutive effect on earnings per share if the price of the Company’s common stock exceeds the initial exchange price of $45.58 per share for a specified period of time. In the event the Company’s common stock exceeds $45.58 per share for a specified period of time, the first $1.00 the price exceeds $45.58 would cause a dilutive effect of approximately 188,400 shares. As the share price continues to increase, dilution would continue to occur but at a declining rate. The impact on the calculation of earnings per share varies depending on when during the quarter the $45.58 per share price is reached (see note 8).
 
(q)   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 $708.3 million at December 31, 2007.
 
(r)   Foreign Currency
 
    Results of operations for foreign subsidiaries with functional currencies other than the U.S. dollar are translated using average exchange rates during the period. Assets and liabilities of these foreign subsidiaries are translated using the exchange rates in effect at the balance sheet dates, and the resulting translation adjustments are reported as accumulated other comprehensive income in the Company’s stockholders’ equity.
 
 
    For non-U.S. subsidiaries where the functional currency is the U.S. dollar, financial statements 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 $0.5 million, $0.8 million, and $(0.2) million of these transaction (gains) losses in general and administrative expenses in the years ended December 31, 2007, 2006 and 2005, respectively.
 
(s)   Stock Based Compensation
 
    Effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123(R) (FAS No. 123(R)), “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).
 
    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.
 
(t)   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

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    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 and 2005, hedging settlement payments reduced oil and gas revenues by approximately $13.8 million and $10.2 million respectively. The Company did not record any material gains or losses due to hedge ineffectiveness for these periods.
 
(u)   Other Comprehensive Income (Loss)
 
    The following table reconciles the change in accumulated other comprehensive income (loss) for the years ended December 31, 2007 and 2006 (amounts in thousands):
                 
    Year Ended December 31,  
    2007     2006  
Accumulated other comprehensive income (loss), net, December 31, 2006 and 2005, respectively
  $ 10,288     $ (4,916 )
Other comprehensive income (loss), net of tax:
               
Hedging activities:
               
Reclassification adjustment for settled contracts, net of tax of $5,124 in 2006
          8,726  
Changes in fair value of outstanding hedging positions, net of tax of ($1,131) in 2006
          (1,927 )
Unrealized loss on equity-method investments’ hedging activities, net of tax of $1,515 in 2007
    (2,580 )      
Foreign currency translation adjustment
    1,370       8,405  
 
           
Total other comprehensive (loss) income
    (1,210 )     15,204  
 
           
 
               
Accumulated other comprehensive income, net, December 31, 2007 and 2006, respectively
  $ 9,078     $ 10,288  
 
           

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(2) Supplemental Cash Flow Information
The following table includes the Company’s supplemental cash flow information for the years ended December 31, 2007, 2006 and 2005 (amounts in thousands):
                         
    2007     2006     2005  
Cash paid for interest
  $ 32,049     $ 32,295     $ 21,152  
 
                 
Cash paid for income taxes
  $ 69,233     $ 100,431     $ 10,789  
 
                 
Details of business acquisitions:
                       
Fair value of assets
  $ 148,658     $ 460,771     $ 6,627  
Fair value of liabilities
    (32,757 )     (76,887 )     (31 )
Note payable due on acquisition
    (300 )            
Common stock issued
          (136,341 )      
 
                 
Cash paid
    115,601       247,543       6,596  
Less cash acquired
    (4,628 )     (8,204 )     (161 )
 
                 
Net cash paid for acquisitions
  $ 110,973     $ 239,339     $ 6,435  
 
                 
Details of oil and gas property acquisitions:
                       
Fair value of assets received
  $ 12,806     $ 50,350     $ 11,494  
Fair value of assets disposed
    (4,806 )            
Fair value of liabilities
          (3,719 )     (11,494 )
 
                 
Cash paid
    8,000       46,631        
Less cash acquired
                (3,686 )
 
                 
Net cash paid for acquisitions
  $ 8,000     $ 46,631     $ (3,686 )
 
                 
Details of proceeds from sale of business:
                       
Book value of assets
  $ 12,617     $ 19,855     $ 16,044  
Book value of liabilities
          (1,168 )      
Note receivable due from sale
    (2,000 )            
Gain on sale of business
    7,483             3,544  
 
                 
Cash received
    18,100       18,687       19,588  
Less cash sold
          (344 )      
 
                 
Net cash proceeds from sale of subsidiary
  $ 18,100     $ 18,343     $ 19,588  
 
                 
Non-cash investing activity:
                       
Receivable from sale of affiliate
  $     $     $ 1,305  
 
                 
 
                       
Non-cash financing activity:
                       
Deferred tax asset on purchase of common stock call options related to exchangeable notes
  $     $ 35,520     $  
 
                 
(3) Stock-Based and Long-Term Compensation
The Company maintains the various incentive plans that provide long-term incentives to the Company’s key employees, including officers and directors, consultants and advisers (Eligible Participants). Under the various incentive plans, 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. 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.

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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 December 6, 2007, the Company granted 157,035 non-qualified stock options from its 2005 Stock Incentive Plan under these same terms.
Beginning January 1, 2006, the Company adopted FAS No. 123(R) 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. 123(R), 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, 2007, 2006 and 2005 and the related assumptions used to calculate the fair value:
                         
    Years Ended December 31,  
    2007     2006     2005  
    Actual     Actual     Pro Forma  
Weighted-average fair value of grants
  $ 14.34     $ 13.02     $ 7.47  
 
                 
Black-Scholes-Merton Assumptions:
                       
Risk free interest rate
    3.67 %     4.57 %     3.85 %
Expected life (years)
    5       5       6  
Volatility
    38.90 %     44.36 %     38.91 %
Dividend yield
                 
The Company’s compensation expense related to stock options for the years ended December 31, 2007 and 2006 was approximately $1.5 million and $0.8 million, respectively, which is reflected in general and administrative expenses. No compensation expense related to options was recorded during the year ended December 31, 2005.
The pro forma data presented below show the effects of stock option costs had they been expensed for the period ending December 31, 2005 (amounts are in thousands, except per share amounts):
         
    2005  
Net income, as reported
  $ 67,859  
Stock-based employee compensation expense, net of tax
    (4,421 )
 
     
Pro forma net income
  $ 63,438  
 
     
 
       
Basic earnings per share:
       
Earnings, as reported
  $ 0.87  
Stock-based employee compensation expense, net of tax
    (0.06 )
 
     
Pro forma earnings per share
  $ 0.81  
 
     
 
       
Diluted earnings per share:
       
Earnings, as reported
  $ 0.85  
Stock-based employee compensation expense, net of tax
    (0.06 )
 
     
Pro forma earnings per share
  $ 0.79  
 
     

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The following table summarizes stock option activity for the years ended December 31, 2007, 2006 and 2005:
                                 
                    Weighted        
            Weighted     Average     Aggregate  
            Average     Remaining     Intrinsic  
    Number of     Option     Contractual     Value (in  
    Options     Price     Term (in years)     thousands)  
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                  
Granted
    157,035     $ 35.84                  
Exercised
    (867,916 )   $ 9.72                  
Forfeited
    (2,333 )   $ 9.20                  
 
                             
Outstanding at December 31, 2007
    3,257,672     $ 14.87       6.6     $ 64,075  
 
                       
Exercisable at December 31, 2007
    2,873,821     $ 12.61       6.2     $ 62,738  
 
                       
Options expected to vest
    383,851     $ 13.87       9.1     $ 1,337  
 
                       
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, 2007 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 December 31, 2007. 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, 2007 (the difference between the stock price upon exercise and the option price) was approximately $25.4 million. The Company received approximately $8.4 million and $2.8 million during the years ended December 31, 2007 and 2006, respectively, from employee stock option exercises. In accordance with FAS No. 123(R), the Company has reported the tax benefits of approximately $9.4 and $1.4 million from the exercise of stock options for the years ended December 31, 2007 and 2006, respectively, as financing cash flows. Prior to implementation of FAS No. 123(R), 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.

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A summary of information regarding stock options outstanding at December 31, 2007 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    
 
    20,000     1.5 years   $ 5.75       20,000     $ 5.75  
$ 7.31 - $8.79    
 
    174,344     4.2 years   $ 8.37       174,344     $ 8.37  
$ 9.10 - $9.90    
 
    508,876     4.0 years   $ 9.42       508,876     $ 9.42  
$ 10.36 - $10.90    
 
    1,370,000     6.6 years   $ 10.66       1,370,000     $ 10.66  
$ 12.45 - $17.46    
 
    687,200     7.4 years   $ 17.42       687,200     $ 17.43  
$ 24.90 - $25.00    
 
    212,600     8.1 years   $ 24.99       70,869     $ 24.99  
$ 35.60 - $35.70    
 
    127,617     9.0 years   $ 35.69       42,532     $ 35.69  
$ 35.80 - $35.90    
 
    157,035     9.9 years   $ 35.84           $  
The following table summarizes non-vested stock option activity for the year ended December 31, 2007:
                 
            Weighted  
            Average  
            Grant-  
    Number of     Date Fair  
    Options     Value  
Non-vested at December 31, 2006
    340,217     $ 13.02  
Granted
    157,035     $ 14.34  
Vested
    (113,401 )   $ 13.02  
Forfeited
        $  
 
             
Non-vested at December 31, 2007
    383,851     $ 13.87  
 
           
As of December 31, 2007, there was approximately $4.4 million of unrecognized compensation expense related to non-vested stock options outstanding. The Company expects to recognize approximately $2.1 million, $1.5 million and $0.8 million of compensation expense during the years 2008, 2009 and 2010, respectively, for these non-vested stock options outstanding.
Restricted Stock
During the year ended December 31, 2007, the Company granted 165,467 shares of restricted stock to its employees. Restricted stock grants vest in equal annual installments over three years. Non-vested shares are generally forfeited upon the termination of employment. Holders 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 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 restricted stock outstanding for the years ended December 31, 2007, 2006 and 2005 was approximately $2.7 million, $1.0 million and $0.2 million, respectively, which is reflected in general and administrative expenses.

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A summary of the status of restricted stock for the year ended December 31, 2007 is presented in the table below:
                 
            Weighted  
            Average Grant  
    Number     Date Fair  
    of Shares     Value  
Non-vested at December 31, 2006
    257,775     $ 30.78  
Granted
    165,467     $ 35.83  
Vested
    (40,835 )   $ 24.48  
Forfeited
    (5,233 )   $ 32.06  
 
             
Non-vested at December 31, 2007
    377,174     $ 33.67  
 
           
As of December 31, 2007, there was approximately $10.0 million of unrecognized compensation expense related to non-vested restricted stock. The Company expects to recognize approximately $4.3 million, $3.7 million and $2.0 million during the years 2008, 2009 and 2010, respectively, for non-vested restricted stock.
Restricted Stock Units
In May 2007, 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 as designated by the Board of Directors, currently having an annual aggregate value of $140,000. The exact number of units is determined by dividing $140,000 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, 58,368 restricted stock units were outstanding at December 31, 2007. The Company’s expense related to restricted stock units for the years ended December 31, 2007, 2006 and 2005 was approximately $1.0 million, $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, 2007 is presented in the table below:
                 
    Number of     Weighted  
    Restricted     Average Grant  
    Stock Units     Date Fair Value  
Outstanding at December 31, 2006
    37,482     $ 21.06  
Granted
    20,886     $ 40.22  
 
             
Outstanding at December 31, 2007
    58,368     $ 27.91  
 
           
Performance Share Units
The Company grants performance share units (PSUs) to its key employees as part of the Company’s long-term incentive program. There is a three-year performance period associated with each PSU grant. 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, 2007, there were 188,359 PSUs outstanding (30,596, 32,112, 54,789 and 70,862 related to performance periods ending December 31, 2007, 2008, 2009 and 2010, respectively). The Company’s compensation expense related to all outstanding PSUs for the years ended December 31, 2007, 2006 and 2005 was approximately $7.2 million, $3.5 million and $1.0 million, respectively, which is reflected in general and

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administrative expenses. At December 31, 2007, the Company has recorded a liability of approximately $11.8 million for all outstanding PSUs which is reflected in accrued expenses and other long-term liabilities.
Employee Stock Purchase Plan
In 2007, the Company adopted an Employee Stock Purchase Plan (ESPP) and a Global Purchase Plan (GPP) under which 1,250,000 shares of common stock were reserved for issuance. Under the ESPP, each eligible employee may direct up to 20% of their salary to a maximum of $8,500 per year toward the purchase of the Company’s common stock at a 15% discount. In accordance with the GPP, the Company may reimburse certain eligible employees of the Company’s foreign subsidiaries for a portion of the purchase price of shares of the Company’s common stock that such employees may purchase on the open market. For the year ended December 31, 2007, 26,163 shares have been issued pursuant to the ESPP. The Company received $0.8 million related to shares issued under the ESPP for the year ended December 31, 2007. The Company recorded compensation expense of approximately $143,000 for year ended December 31, 2007 related to these stock purchase plans.
(4) Acquisitions and Dispositions
In August 2007, the Company sold the assets of a non-core rental tool business for approximately $16.3 million in cash and $2.0 million in a note receivable bearing interest at the prime rate and maturing in August 2010. As a result of this asset sale, the Company recorded a pre-tax gain of approximately $7.5 million. In conjunction with the sale, an additional $3.4 million will be payable to the Company if specified conditions are met as determined through August 2011.
In April 2007, the Company acquired Advanced Oilwell Services, Inc. (AOS) for approximately $24.2 million in cash consideration. Additional consideration of up to $7.4 million will be based upon the average earnings before interest, income taxes, depreciation and amortization expense over a three-year period. AOS is a provider of cementing and pressure pumping services primarily operating in the East Texas region. The acquisition has been accounted for as a purchase, and the results of operations have been included from the acquisition date. The pro forma effect of the operations of the acquisition was not material to the Consolidated Statements of Operations of the Company for 2007.
In January 2007, the Company acquired Duffy & McGovern Accommodation Services Limited (Duffy & McGovern) for approximately $47.5 million in cash consideration. Duffy & McGovern is a provider of offshore accommodation rentals operating in most deep water oil and gas territories with major operations in Europe, Africa, the Americas and South East Asia. The Company acquired Duffy & McGovern to further expand its rental tools segment internationally. The acquisition has been accounted for as a purchase, and the results of operations have been included from the acquisition date. The pro forma effect of the operations of the acquisition was not material to the Consolidated Statements of Operations of the Company for 2007.
On December 12, 2006, the Company completed its acquisition of 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). 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’s operations are concentrated in the major onshore and offshore oil and gas producing areas of the United States. The Company acquired Warrior to further strengthen its well intervention operations in 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 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 were finalized during the 12 months following the acquisition date as information regarding taxes, litigation and other items became more discernible. The acquisition has been accounted for as a purchase, and the results of operations of Warrior have been included from the acquisition date.

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In July 2006, Beryl Oil & Gas L.P. (BOG), formerly known as Coldren Resources LP, 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 BOG for an initial cash investment of $57.8 million. The Company’s investment in BOG is accounted for under the equity-method of accounting (see note 6). Amounts included in the pro forma information below contain the Company’s 40% ownership interest in the performance of the Noble properties prior to their acquisition by BOG 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 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 $43.3 million in 2007 and $9.8 million in 2006. SPN Resources acquired additional oil and gas producing assets in December 2007 of approximately $12.8 million for $8.0 million in cash consideration and exchanged other oil and gas producing assets with a fair value and net book value of approximately $4.8 million. The Company sold the assets of its field management division in 2007 for approximately $1.8 million in cash. In conjunction with the sale of this division, an additional $0.5 million will be receivable by the Company if specific conditions are met as determined through 2008. Also, the Company sold its environmental subsidiary in 2006 for approximately $18.7 million in cash.
The following unaudited pro forma information for the year ended December 31, 2006 presents a summary of the consolidated results of operations as if the business acquisitions and disposition occurring during the year ended December 31, 2006, as described above, had occurred on January 1, 2006, 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):
         
    Year Ended  
    December 31,  
    2006  
Revenues
  $ 1,221,259  
 
     
Net income
  $ 206,286  
 
     
Basic earnings per share
  $ 2.57  
 
     
Diluted earnings per share
  $ 2.52  
 
     
The above pro forma information is not necessarily indicative of the results of operations that would have been achieved had the acquisitions and disposition occurring during the year ended December 31, 2006 been effected on January 1, 2006.
Several of the Company’s prior business acquisitions require future payments if specific conditions are met. As of December 31, 2007, the maximum additional consideration payable was approximately $29.5 million, and will be determined and payable through 2012. These amounts are not classified as liabilities under generally accepted accounting principles and are not reflected in the Company’s financial statements until the amounts are fixed and determinable. When they are determined, they are capitalized as part of the purchase price of the related acquisition. In April 2007, the Company paid additional consideration of $0.6 million as a result of a prior acquisition.

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(5) Property, Plant and Equipment
A summary of property, plant and equipment at December 31, 2007 and 2006 (in thousands) is as follows:
                 
    2007     2006  
Buildings, improvements and leasehold improvements
  $ 64,459     $ 53,240  
Marine vessels and equipment
    224,856       217,422  
Machinery and equipment
    857,762       561,570  
Automobiles, trucks, tractors and trailers
    42,981       23,829  
Furniture and fixtures
    21,784       17,274  
Construction-in-progress
    73,762       48,274  
Land
    9,250       7,328  
 
           
 
    1,294,854       928,937  
Accumulated depreciation
    (416,502 )     (302,379 )
 
           
Property, plant and equipment, net
  $ 878,352     $ 626,558  
 
           
 
               
Oil and gas assets
    307,674       229,329  
Accumulated depletion
    (99,618 )     (51,659 )
 
           
Oil and gas assets, net, under the successful efforts method of accounting
  $ 208,056     $ 177,670  
 
           
The Company has approximately $13 million and $11 million of leasehold improvements at December 31, 2007 and 2006, 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 $121.3 million, $79.3 million and $68.6 million for the years ended December 31, 2007, 2006 and 2005, 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 or losses from equity-method investments on its Consolidated Statements of Operations.
In May 2006, SPN Resources acquired a 40% interest in BOG. The Company made total cash contributions for its initial equity-method investment of approximately $57.8 million in 2006 and has not made additional contributions in 2007. The Company’s equity-method investment balance in BOG is approximately $56.0 million and $63.6 million at December 31, 2007 and 2006, respectively. The earnings (loss) from the equity-method investment in BOG was approximately ($3.0) million and $5.8 million for the years ended December 31, 2007 and 2006, respectively. BOG had total proved reserves of approximately 4,579 Mbbls of oil and 75,646 Mmcf of gas at December 31, 2007.
The Company provides operating and administrative support services to BOG and receives reimbursement for general and administrative and direct expenses incurred on behalf of BOG. The Company, where possible and at competitive rates, provides its products and services to assist BOG in producing and developing its oil and gas properties. At December 31, 2007 and 2006, the Company had receivables of approximately $1.9 million and $3.0 million, respectively, due from BOG. The Company reduced its general and administrative expenses by approximately $4.1 million and $1.7 million by the reimbursements due from BOG for 2007 and 2006, respectively. The Company also recorded revenue of approximately $8.0 million and $1.4 million from BOG in 2007 and 2006, respectively. The Company reduces its revenue and its investment in BOG for its 40% ownership when products and services are provided to and capitalized by BOG. The Company records these amounts in revenue as BOG records the related depreciation and depletion expenses. The Company recorded a net reduction to revenue and its

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investment in BOG of approximately $606,000 and $23,000 for the years ended December 31, 2007 and 2006, respectively, as a result of these adjustments.
Also included in equity-method investments at December 31, 2007 and 2006 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 $11,000, $23,000 and $9,000 for the years ended December 31, 2007, 2006 and 2005, respectively. The Company recorded approximately $208,000, $227,000 and $195,000 in expense to lease the airplane from this company for the years ended December 31, 2007, 2006 and 2005, respectively.
In 2005, the Company sold its equity-method investment in a rental tool company. The Company received approximately $12.5 million in cash in 2005 and $1.0 million in 2007 as a result of the sale. The Company reduced the value of this investment by approximately $1.3 million during 2005 in anticipation of this sale.
(7) Construction Contract
In July 2006, the Company contracted to construct a derrick barge that will be sold to a third party for approximately $53.1 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, 2007 and 2006 is approximately $25.0 million and $12.3 million, respectively, of billings in excess of costs and estimated earnings related to this contract.
On December 31, 2007, the Company’s wholly-owned subsidiary, Wild Well Control, Inc. (Wild Well), entered into contractual arrangements pursuant to which it will decommission seven downed oil and gas platforms and related well facilities located offshore in the Gulf of Mexico for a fixed sum of $750 million, which is payable in installments upon the completion of specified portions of work. The contract contains certain covenants primarily related to Wild Well’s performance of the work. The work is expected to take approximately three years to complete and will commence in the first quarter of 2008. The contract will be accounted for using the percentage-of-completion method. The Company will measure progress on this contract based on the ratio of costs incurred to total estimated costs.
(8) Long-Term Debt
The Company’s long-term debt as of December 31, 2007 and 2006 consisted of the following (in thousands):
                 
    2007     2006  
Senior Notes — interest payable semiannually at 6.875%, due June 2014
  $ 300,000     $ 300,000  
Discount on 6.875% Senior Notes
    (3,825 )     (4,281 )
Senior Exchangeable Notes — interest payable semiannually at 1.5% until December 2011 and 1.25% thereafter, due December 2026
    400,000       400,000  
U.S. Government guaranteed long-term financing — interest payable semianually at 6.45%, due in semiannual installments through June 2027
    15,786       16,596  
Revolver — interest payable monthly at floating rate, due in June 2011
           
 
           
 
    711,961       712,315  
Less current portion
    810       810  
 
           
Long-term debt
  $ 711,151     $ 711,505  
 
           

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The Company has a $250 million bank revolving credit facility. Any balance outstanding on the revolving credit facility is due on June 14, 2011. At December 31, 2007, the Company had no borrowings under this revolving credit facility but had letters of credit outstanding of approximately $94.3 million, which reduce the Company’s borrowing capacity under the revolving credit facility. Amounts borrowed 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, 2007, the Company was in compliance with all such covenants.
The Company has $15.8 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 the maturity date of June 3, 2027. The Company’s obligations are secured by mortgages on the two liftboats. In accordance with this 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, 2007, the Company was in compliance with all such covenants. This long-term financing ranks equally with the bank credit facility and both are secured by different collateral.
The Company has $300 million of 6 7/8% unsecured senior notes due 2014. 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, limit 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, 2007, the Company was in compliance with all such covenants.
The Company also has $400 million of 1.50% unsecured senior exchangeable notes due 2026. The exchangeable 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 on December 15th and June 15th of each year through the maturity date of December 15, 2026. The exchangeable notes do not contain any restrictive financial covenants.
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 entered into agreements to purchase call options and sell warrants on its common stock (see note 10).

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In 2006, the Company recognized a loss on the early extinguishment of debt of approximately $12.6 million due to the repayment of its $200 million 8 7/8% unsecured senior notes due 2011. The loss included premiums paid, fees and expenses and the write-off of the remaining unamortized debt acquisition costs associated with these notes.
Annual maturities of long-term debt for each of the five fiscal years following December 31, 2007 and thereafter are as follows (in thousands):
         
2008
  $ 810  
2009
    810  
2010
    810  
2011
    810  
2012
    810  
Thereafter
    711,736  
 
     
 
       
Total
  $ 715,786  
 
     
(9) Income Taxes
The components of income tax expense (benefit) for the years ended December 31, 2007, 2006 and 2005 are as follows (in thousands):
                         
    2007     2006     2005  
Current
                       
Federal
  $ 67,211     $ 75,017     $ 30,745  
State
    2,917       1,373       898  
Foreign
    19,470       11,552       6,087  
 
                 
 
                       
 
    89,598       87,942       37,730  
 
                 
 
                       
Deferred
                       
Federal
    60,161       16,894       1,895  
State
    1,170       1,444       94  
Foreign
    443       (2,675 )     (1,547 )
 
                 
 
                       
 
    61,774       15,663       442  
 
                 
 
                       
 
  $ 151,372     $ 103,605     $ 38,172  
 
                 
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, 2007, 2006 and 2005 as follows (in thousands):
                         
    2007     2006     2005  
Computed expected tax expense
  $ 151,372     $ 102,146     $ 37,111  
Increase (decrease) resulting from:
                       
State and foreign income taxes
    2,059       (14 )     242  
Other
    (2,059 )     1,473       819  
 
                 
 
                       
Income tax expense
  $ 151,372     $ 103,605     $ 38,172  
 
                 

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The significant components of deferred income taxes at December 31, 2007 and 2006 are as follows (in thousands):
                 
    2007     2006  
Deferred tax assets:
               
Allowance for doubtful accounts
  $ 3,225     $ 5,598  
Operating loss and tax credit carryforwards
    16,927       23,183  
Decommissioning liability
    46,239       45,212  
Deferred interest expense related to exchangeable notes
    29,358       35,520  
Other
    26,810       13,183  
 
           
 
    122,559       122,696  
Valuation allowance
    (3,245 )     (6,370 )
 
           
 
               
Net deferred tax assets
    119,314       116,326  
 
           
 
               
Deferred tax liabilities:
               
Property, plant and equipment
    214,862       168,523  
Note receivable
    11,190       11,455  
Goodwill and other intangible assets
    49,528       46,810  
Other
    7,072       1,549  
 
           
 
               
Deferred tax liabilities
    282,652       228,337  
 
           
 
               
Net deferred tax liability
  $ 163,338     $ 112,011  
 
           
The net deferred tax assets reflect management’s estimate of the amount that will be realized from future profitability and the reversal of taxable temporary differences that can be predicted with reasonable certainty. A valuation allowance is recognized if it is more likely than not that at least some portion of any deferred tax asset will not be realized.
As of December 31, 2007, the Company has approximately $40.6 million in net operating loss carryforwards, which are available to reduce future taxable income. The expiration dates for utilization of the loss carryforwards are 2019 through 2025. 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. At December 31, 2007 and 2006, the Company has recorded a valuation allowance of approximately $3.2 million and $6.4 million, respectively, against its deferred tax assets to reflect the estimated expiration of net operating loss carryforwards. The change in the valuation allowance was recorded as a reduction of goodwill, as it related to additional operating losses acquired in a prior year business combination.
At December 31, 2007 the Company had a capital loss carryforward in the amount of $2.3 million. The Company has recorded a valuation allowance against the capital loss carryforward because it is uncertain that the capital loss will be utilized in the future.
At December 31, 2007, the Company has an estimated $0.8 million foreign tax credit carryforward which expires in 2014. The Company also has state net operating loss carryforwards at December 31, 2007 of an estimated $1.0 million which expire in 2015.
The Company has not provided United States income tax expense on earnings of its foreign subsidiaries, since the Company has reinvested or expects to reinvest the undistributed earnings indefinitely. At December 31, 2007, the undistributed earnings of the Company’s foreign subsidiaries were approximately $87.4 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.
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 the

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measurement and recognition in accounting for income tax uncertainties. The Company adopted the provisions of FIN 48 on January 1, 2007. As a result of the implementation, the Company recognized no material adjustment to the liability for unrecognized income tax benefits that existed as of December 31, 2006.
It is the Company’s policy to recognize interest and applicable penalties related to uncertain tax positions in income tax expense.
The Company files income tax returns in the U.S. federal and various state and foreign jurisdictions. The number of years that are open under the statue of limitations and subject to audit varies depending on the tax jurisdiction. The Company remains subject to U.S. federal tax examinations for years after 2003.
The Company had approximately $7.7 million of unrecorded tax benefits at December 31, 2007, all of which would impact the Company’s effective tax rate if recognized. The unrecorded tax benefits are not considered material to the Company’s financial position.
(10) Stockholders’ Equity
In 2007, Company’s Board of Directors authorized a $350 million share repurchase program of the Company’s common stock, which will expire on December 31, 2009. Under the program, the Company may purchase shares through open market transactions at prices deemed appropriate by management. The Company purchased and retired 1,000,000 shares of its common stock for an aggregate amount of approximately $33.8 million under the program in 2007.
In 2006, the Company issued 5,369,888 shares of common stock valued at $25.39 per share totaling $136.3 million for the acquisition of Warrior Energy Services Corporation.
In 2006, concurrently with the closing of the 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.
Also in connection with the exchangeable note transaction in 2006, the Company entered into agreements 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.
(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 2005, the Company elected to not reopen its oil spill containment boom manufacturing facility after it suffered damage from Hurricane Katrina and experienced difficulty in resuming normal business operations. The Company reduced the value of the assets of this business (which consisted primarily of inventory and property and equipment) by approximately $1.1 million to their estimated net realizable value.

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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 Business
In August 2007, the Company sold the assets of a non-core rental tool business for approximately $16.3 million in cash and $2.0 million in a note receivable bearing interest equal to prime rate per annum due in August 2010. As a result of the sale of these assets, the Company recorded a pre-tax gain on sale of business of approximately $7.5 million. In conjunction with the sale of this business, an additional $3.4 million will be receivable and recognized by the Company if specific conditions are met as determined through August 2011.
In June 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 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 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 may provide a discretionary match, not to exceed 5% of an employee’s salary. The Company made contributions of approximately $3.7 million, $2.7 million and $1.9 million in 2007, 2006 and 2005, 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 base 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. At December 31, 2007 and 2006, the liability of the Company to the participants was approximately $7.6 million and $3.9 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. At December 31, 2007 and 2006, the deferred contribution plan asset was approximately $7.6 million and $4.3 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 $7.8 million in 2007, $4.2 million in 2006 and $4.3 million in 2005. Future minimum lease payments under non-cancelable leases for the five years ending December 31, 2008 through 2012 and thereafter are as follows (amounts in thousands): $14,800, $7,167, $4,018, $2,774, $1,221 and $15,253, 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 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. Certain previously reported amounts have been reclassified to conform to the presentation in the current year.
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 BOG of approximately $56.0 million and $63.6 million at December 31, 2007 and 2006, respectively, is included in the identifiable assets of the oil and gas segment.
Summarized financial information concerning the Company’s segments as of December 31, 2007, 2006 and 2005 and for the years then ended is shown in the following tables (in thousands):
                                                 
                                    Oil & Gas    
    Well   Rental                   Eliminations   Consolid.
2007   Interven.   Tools   Marine   Oil & Gas   & Unallocated   Total
               
Revenues
  $ 761,015     $ 496,290     $ 127,898     $ 192,700     $ (5,436 )   $ 1,572,467  
Cost of services, rentals, and sales
    419,818       156,731       60,432       66,580       (5,436 )     698,125  
Depreciation, depletion, amortization and accretion
    49,786       70,042       8,861       59,152             187,841  
General and administrative
    118,657       87,442       10,592       11,455             228,146  
Gain on sale of business
          7,483                         7,483  
Income from operations
    172,754       189,558       48,013       55,513             465,838  
Interest expense, net
                            (33,257 )     (33,257 )
Interest income
                      1,219       1,632       2,851  
Losses from equity-method investments
                      (2,940 )           (2,940 )
               
 
                                               
Income before income taxes
  $ 172,754     $ 189,558     $ 48,013     $ 53,792     $ (31,625 )   $ 432,492  
               
 
                                               
Identifiable assets
  $ 996,946     $ 687,944     $ 200,623     $ 344,667     $ 27,069     $ 2,257,249  
 
                                               
Capital expenditures
  $ 145,061     $ 166,944     $ 19,200     $ 75,725     $ 3,588     $ 410,518  

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                                    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
  $ 840,130     $ 501,156     $ 187,597     $ 318,297     $ 27,298     $ 1,874,478  
 
                                               
Capital expenditures
  $ 54,104     $ 111,270     $ 10,412     $ 64,237     $ 2,913     $ 242,936  
                                                 
                                    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  
Costs 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 sale of liftboats
    4,850                   2,144               6,994  
Gain on sale of business
                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  
Earnings from equity-method investments
          (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  

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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):
                                         
    Revenues   Long-Lived Assets
    Years Ended December 31,   December 31,
    2007   2006   2005   2007   2006
United States
  $ 1,273,705     $ 924,582     $ 636,062     $ 904,611     $ 715,899  
Other Countries
    298,762       169,239       99,272       181,797       88,329  
         
Total
  $ 1,572,467     $ 1,093,821     $ 735,334     $ 1,086,408     $ 804,228  
               
(16) Interim Financial Information (Unaudited)
The following is a summary of consolidated interim financial information for the years ended December 31, 2007 and 2006. Gross profit is calculated by subtracting cost of services, rentals and sales from revenue. (Amounts in thousands, except per share data.)
                                 
    Three Months Ended
    March 31   June 30   Sept. 30   Dec. 31
2007
                               
Revenues
  $ 362,924     $ 396,753     $ 398,924     $ 413,866  
Gross profit
    202,437       214,947       220,287       236,671  
Net income
    64,019       70,087       75,050       71,964  
 
                               
Earnings per share:
                               
Basic
  $ 0.79     $ 0.86     $ 0.92     $ 0.89  
Diluted
    0.78       0.85       0.91       0.88  
                                 
    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  
(17) Financial Information Related to Guarantor Subsidiaries
SESI, L.L.C. (Issuer), a wholly-owned subsidiary of Superior Energy Services, Inc. (Parent), has issued and outstanding $300 million of 6 7/8% Senior Notes due 2014 and $400 million of 1.5% senior exchangeable notes due 2026. The Parent, along with substantially all of its domestic subsidiaries, fully and unconditionally guaranteed the senior notes and the 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, 2007 and 2006 and the Consolidating Statements of Operations and Cash Flows for the years ended December 31, 2007, 2006 and 2005.

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidating Balance Sheets
December 31, 2007
(in thousands)
                                                 
                            Non-              
                    Guarantor     Guarantor              
    Parent     Issuer     Subsidiaries     Subsidiaries     Eliminations     Consolidated  
ASSETS
                                               
 
                                               
Current assets:
                                               
Cash and cash equivalents
  $     $ 12,325     $ 12,485     $ 26,839     $     $ 51,649  
Accounts receivable, net
          3,344       306,198       49,854       (16,062 )     343,334  
Income taxes receivable
    131                         (131 )      
Current portion of notes receivable
                15,584                   15,584  
Prepaid expenses
          5,598       9,068       4,975             19,641  
Other current assets
          1,299       37,558       1,940             40,797  
 
                                   
 
                                               
Total current assets
    131       22,566       380,893       83,608       (16,193 )     471,005  
 
                                   
 
                                               
Property, plant and equipment, net
          4,727       945,306       136,375             1,086,408  
Goodwill, net
                442,637       41,957             484,594  
Notes receivable
          2,000       14,658       74             16,732  
Equity-method investments
    124,271       563,034       55,974             (686,318 )     56,961  
Intangible and other long-term assets, net
          23,935       109,649       7,965             141,549  
 
                                   
 
                                               
Total assets
  $ 124,402     $ 616,262     $ 1,949,117     $ 269,979     $ (702,511 )   $ 2,257,249  
 
                                   
LIABILITIES AND STOCKHOLDERS’ EQUITY
                                               
 
                                               
Current liabilities:
                                               
Accounts payable
  $     $ 1,015     $ 57,063     $ 27,494     $ (16,062 )   $ 69,510  
Accrued expenses
    557       46,521       118,906       11,795             177,779  
Income taxes payable
                      7,651       (131 )     7,520  
Current portion of decommissioning liabilities
                36,812                   36,812  
Current maturities of long-term debt
                      810             810  
 
                                   
 
                                               
Total current liabilities
    557       47,536       212,781       47,750       (16,193 )     292,431  
 
                                   
 
                                               
Deferred income taxes
    153,649                   9,689             163,338  
Decommissioning liabilities
                88,158                   88,158  
Long-term debt
          696,175             14,976             711,151  
Intercompany payables/(receivables)
    (134,052 )     26,078       583,338       54,933       (530,297 )      
Other long-term liabilities
    7,716       13,449             327             21,492  
 
                                               
Stockholders’ equity:
                                               
Preferred stock of $.01 par value.
                                   
Common stock of $.001 par value.
    81                   126       (126 )     81  
Additional paid in capital
    401,455       127,173             28,722       (155,895 )     401,455  
Accumulated other comprehensive income (loss)
                (2,580 )     11,658             9,078  
Retained earnings (deficit)
    (305,004 )     (294,149 )     1,067,420       101,798             570,065  
 
                                   
 
                                               
Total stockholders’ equity
    96,532       (166,976 )     1,064,840       142,304       (156,021 )     980,679  
 
                                   
 
                                               
Total liabilities and stockholders’ equity
  $ 124,402     $ 616,262     $ 1,949,117     $ 269,979     $ (702,511 )   $ 2,257,249  
 
                                   

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidating Balance Sheets
December 31, 2006
(in thousands)
                                                 
                            Non-              
                    Guarantor     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 expenses
          15,890       64       1,828             17,782  
Other current assets
          692       40,392       697             41,781  
 
                                   
 
                                               
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       23,151       104,866       8,642             137,164  
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       24,196       198,544       34,773       (19,443 )     238,575  
 
                                   
 
                                               
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       8,456                         14,653  
 
                                               
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 Statements of Operations
Year Ended December 31, 2007
(in thousands)
                                                 
                            Non-              
                    Guarantor     Guarantor              
    Parent     Issuer     Subsidiaries     Subsidiaries     Eliminations     Consolidated  
Oilfield service and rental revenues
  $     $     $ 1,232,297     $ 183,402     $ (35,932 )   $ 1,379,767  
Oil and gas revenues
                192,700                   192,700  
 
                                   
 
                                               
Total revenues
                1,424,997       183,402       (35,932 )     1,572,467  
 
                                   
 
                                               
Cost of oilfield services and rentals
                580,222       87,255       (35,932 )     631,545  
Cost of oil and gas sales
                66,580                   66,580  
 
                                   
 
                                               
Total cost of services, rentals and sales
                646,802       87,255       (35,932 )     698,125  
 
                                   
 
                                               
Depreciation, depletion, amortization and accretion
          665       170,368       16,808             187,841  
General and administrative expenses
    855       52,966       152,815       21,510             228,146  
Gain on sale of business
          7,483                         7,483  
 
                                   
 
                                               
Income from operations
    (855 )     (46,148 )     455,012       57,829             465,838  
 
                                   
 
                                               
Other income (expense):
                                               
Interest expense, net
          (30,916 )     (1,296 )     (1,045 )           (33,257 )
Interest income
          399       1,449       1,003             2,851  
Earnings (losses) from equity-method investments
          11       (2,951 )                 (2,940 )
 
                                   
 
                                               
Income before income taxes
    (855 )     (76,654 )     452,214       57,787             432,492  
 
                                               
Income taxes
    133,064                   18,308             151,372  
 
                                   
 
                                               
Net income (loss)
  $ (133,919 )   $ (76,654 )   $ 452,214     $ 39,479     $     $ 281,120  
 
                                   

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidating Statements of Operations
Year Ended December 31, 2006
(in thousands)
                                                 
                            Non-              
                    Guarantor     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)
                                                 
                            Non-              
                    Guarantor     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 business
                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 Cash Flows
Year Ended December 31, 2007
(in thousands)
                                         
                    Guarantor     Non-Guarantor        
    Parent     Issuer     Subsidiaries     Subsidiaries     Consolidated  
Cash flows from operating activities:
                                       
Net income (loss)
  $ (133,919 )   $ (76,654 )     $452,214     $ 39,479     $ 281,120  
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
                                       
Depreciation, depletion, amortization and accretion
          665       170,368       16,808       187,841  
Deferred income taxes
    61,331                   443       61,774  
Stock-based and performance share unit compensation expense
          12,549                   12,549  
(Earnings) losses from equity-method investments
          (11 )     2,951             2,940  
Amortization of debt acquisition costs and note discount
          3,518                   3,518  
Gain on sale of business
          (7,483 )                 (7,483 )
Changes in operating assets and liabilities, net of acquisitions and dispositions:
                                       
Receivables
          (567 )     (24,893 )     99       (25,361 )
Accounts payable
          (31 )     (8,014 )     1,009       (7,036 )
Accrued expenses
    53       17,225       (10,556 )     869       7,591  
Decommissioning liabilities
                (2,769 )           (2,769 )
Income taxes
    6,177                   2,347       8,524  
Other, net
    (533 )     2,797       8,482       (3,482 )     7,264  
 
                             
 
                                       
Net cash provided by (used in) operating activities
    (66,891 )     (47,992 )     587,783       57,572       530,472  
 
                             
 
                                       
Cash flows from investing activities:
                                       
Payments for capital expenditures
          (3,588 )     (363,928 )     (43,002 )     (410,518 )
Acquisitions of businesses, net of cash acquired
          (97,308 )           (13,665 )     (110,973 )
Acquisitions of oil and gas properties, net of cash acquired
                (8,000 )           (8,000 )
Cash proceeds from the sale of business, net
          18,100                   18,100  
Other
          9,091                   9,091  
Intercompany receivables/payables
    82,007       132,497       (218,145 )     3,641        
 
                             
 
                                       
Net cash provided by (used in) investing activities
    82,007       58,792       (590,073 )     (53,026 )     (502,300 )
 
                             
 
                                       
Cash flows from financing activities:
                                       
Principal payments on long-term debt
                      (810 )     (810 )
Payment of debt acquisition costs
          (83 )                 (83 )
Proceeds from exercise of stock options
    8,440                         8,440  
Tax benefit from exercise of stock options
    9,408                         9,408  
Proceeds from issuance of stock through employee benefit plans
    806                         806  
Purchase and retirement of stock
    (33,770 )                       (33,770 )
 
                             
 
                                       
Net cash provided by (used in) financing activities
    (15,116 )     (83 )           (810 )     (16,009 )
 
                             
 
                                       
Effect of exchange rate changes on cash
                      516       516  
 
                             
 
                                       
Net increase (decrease) in cash and cash equivalents
          10,717       (2,290 )     4,252       12,679  
 
                                       
Cash and cash equivalents at beginning of year
          1,608       14,775       22,587       38,970  
 
                             
 
                                       
Cash and cash equivalents at end of year
  $     $ 12,325     $ 12,485     $ 26,839     $ 51,649  
 
                             

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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 and performance share unit 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 )
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 )
Other, net
    (3,789 )     (82 )     12,553       5,210       13,892  
 
                             
 
                                       
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 business, net
          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  
Stock-based and performance share unit compensation expense
          1,404                   1,404  
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 business
                (3,544 )           (3,544 )
Changes in operating assets and liabilities, net of acquisitions and dispositions:
                                       
Receivables
          (2,026 )     (21,849 )     (8,220 )     (32,095 )
Accounts payable
          35       (2,282 )     7,943       5,696  
Accrued expenses
    588       2,602       8,844       3,496       15,530  
Decommissioning liabilities
                (8,772 )           (8,772 )
Income taxes
    25,886                   251       26,137  
Other, net
          568       (13,733 )     1,567       (11,598 )
 
                             
 
                                       
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 the sale of business, net
                19,588             19,588  
Cash proceeds from sale of equity-method investment
                      12,489       12,489  
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 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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(18) Supplementary Oil and Natural Gas Disclosures (Unaudited)
The Company’s December 31, 2007, 2006 and 2005 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, 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  
 
               
Purchase and sale of reserves in place and additions
    1,206       6,862  
Revisions
    519       1,688  
Production
    (1,817 )     (8,931 )
 
               
 
               
December 31, 2007
    7,829       35,260  
 
               
 
               
Proved-developed reserves:
               
December 31, 2005
    7,554       21,703  
December 31, 2006
    6,709       28,982  
December 31, 2007
    6,493       34,742  
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.

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Costs incurred for oil and natural gas property acquisition and development activities for the years ended December 31, 2007, 2006 and 2005 are as follows (in thousands):
                         
    Years Ended December 31,  
    2007     2006     2005  
Acquisition of properties — proved
  $ 12,126     $ 45,948     $ 9,015  
Development costs
    76,928       63,396       19,867  
 
                 
 
                       
Total costs incurred
  $ 89,054     $ 109,344     $ 28,882  
 
                 
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):
                         
    2007     2006     2005  
Future cash inflows
  $ 1,043,327     $ 682,384     $ 792,246  
Future production costs
    (207,749 )     (220,108 )     (155,282 )
Future development and abandonment costs
    (251,071 )     (207,676 )     (195,415 )
Future income tax expense
    (167,305 )     (59,976 )     (171,058 )
 
                 
 
                       
Future net cash flows after income taxes
    417,202       194,624       270,491  
10% annual discount for estimated timing of cash flows
    57,534       15,883       65,386  
 
                 
 
                       
Standardized measure of discounted future net cash flows
  $ 359,668     $ 178,741     $ 205,105  
 
                 

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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, 2007, 2006 and 2005 is as follows (in thousands):
                         
    2007     2006     2005  
Beginning of the period
  $ 178,742     $ 205,105     $ 136,507  
Sales and transfers of oil and natural gas produced, net of production costs
    (130,130 )     (55,184 )     (34,563 )
Net changes in prices and production costs
    247,708       (147,633 )     156,992  
Revisions of quantity estimates
    41,479       (7,071 )     4,314  
Development costs incurred
    (77,239 )     (64,254 )     19,867  
Changes in estimated development costs
    28,761       47,096       (46,113 )
Extensions and discoveries
    106,055       36,906        
Purchase and sales of reserves in place
    15,667       70,304       18,408  
Changes in production rates (timing) and other
    12,545       (22,080 )     (25,536 )
Accretion of discount
    21,247       33,152       22,123  
Net change in income taxes
    (85,167 )     82,401       (46,894 )
 
                 
 
                       
Net increase
    180,926       (26,363 )     68,598  
 
                 
 
                       
End of period
  $ 359,668     $ 178,742     $ 205,105  
 
                 
The December 31, 2007 amount was estimated by DeGolyer and MacNaughton using a period-end crude NYMEX price of $95.98 per barrel (bbl), a NYMEX gas price of $7.48 per million British Thermal units, and price differentials provided by the Company. The December 31, 2006 amount was estimated by DeGolyer and MacNaughton using a period-end crude NYMEX price of $61.05 per bbl, a NYMEX gas price of $5.64 per million British Thermal units, and price differentials provided by the Company. The December 31, 2005 amount was estimated by DeGolyer and MacNaughton using a period-end crude NYMEX price of $61.04 per bbl, a NYMEX gas price of $9.44 per million British Thermal units, and price differentials provided by the Company. Spot prices as of February 18, 2008 were $8.66 per million British Thermal units for natural gas and $100.10 per bbl for crude oil.
(19) Subsequent Event
In February 2008, the Company entered into a purchase agreement to sell 75% of its interest in SPN Resources for approximately $165 million in cash, subject to certain conditions. The transaction is expected to close during the first quarter of 2008. The Company will retain the preferential rights on all service work and has agreed to perform, on a fixed price basis, the decommissioning work associated with oil and gas properties owned and operated by SPN Resources at closing. The major classes of assets and liabilities of SPN Resources include oil and gas assets, notes receivable and decommissioning liabilities. The carrying value of these assets and liabilities are presented separately in the Consolidated Balance Sheets as of December 31, 2007 and 2006.
(20) Accounting Pronouncements
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 applies under other accounting pronouncements that require or permit fair value measurements. FAS No. 157 indicates, among other things, a fair value measurement assumes that the transaction to sell an asset or transfer a liability occurs in the principal market for the asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability. FAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company is currently evaluating the impact that FAS No. 157 will have on its results of operations and financial position.
In February 2007, the Financial Accounting Standards Board issued its Statement of Financial Accounting Standards No. 159 (FAS No. 159), “The Fair Value Option for Financial Assets and Financial Liabilities – Including an

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Amendment of FASB Statement No. 115,” which is effective for fiscal years beginning after November 15, 2007. This statement permits an entity to choose to measure many financial instruments and certain other items at fair value at specified election dates. Subsequent unrealized gains and losses on items for which the fair value option has been elected will be reported in earnings. The Company does not expect the adoption of FAS No. 159 to have a material impact on its results of operations or financial position.
In December 2007, the Financial Accounting Standards Board issued its Statement of Financial Accounting Standards No. 141(R) (FAS No. 141(R)), “Business Combinations (as amended).” FAS No. 141(R) requires an acquiring entity in a business combination to recognize all assets acquired and liabilities assumed in the transaction and any noncontrolling interest in the acquiree at the acquisition date fair value. Additionally, contingent consideration and contractual contingencies shall be measured at acquisition date fair value. FAS No. 141(R) also requires an acquirer to disclose all of the information users may need to evaluate and understand the nature and financial effect of the business combination. Such information includes, among other things, a description of the factors comprising goodwill recognized in the transaction, the acquisition date fair value of the consideration, including contingent consideration, amounts recognized at the acquisition date for each major class of assets acquired and liabilities assumed, transactions not considered to be part of the business combination (i.e., separate transactions), and acquisition-related costs. FAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 (for any acquisitions closed on or after January 1, 2009 for the Company), and early adoption is not permitted. While the Company does not expect the adoption of FAS No. 141(R) to have a material impact to its consolidated financial statements for transactions completed prior to December 31, 2008, the impact of the accounting change could be material for business combinations which may be consummated subsequent thereto.
In December 2007, the Financial Accounting Standards Board issued its Statement of Financial Accounting Standards No. 160 (FAS No. 160), “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51.” FAS No. 160 amends ARB No. 51 to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. Additionally, this statement requires that consolidated net income include the amounts attributable to both the parent and the noncontrolling interest. FAS No. 160 is effective for fiscal years beginning on or after December 15, 2008. The Company is currently evaluating the impact, if any, that the adoption of FAS No. 160 will have on its results of operations and financial position.

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Our management has established and maintains a system of disclosure controls and procedures to provide reasonable assurances that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is appropriately recorded, processed, summarized and reported within the time periods specified by the Securities and Exchange Commission. Based on that evaluation, our principal executive and financial officers have concluded that our disclosure controls and procedures as of December 31, 2007 are effective at the reasonable assurance level. Management’s report and the independent registered public accounting firm’s attestation report are included in Part II, Item 8 under the captions “Management’s Report on Internal Control over Financial Reporting” and “Independent Registered Public Accounting Firm’s Report,” and are incorporated herein by reference.
There has been no change in our internal control over financial reporting during the quarter ended December 31, 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information
None.

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PART III
Item 10. Directors, Executive Officers and Corporate Governance
Information relating to our executive officers is included in Part I, Item 4A, and is incorporated herein as reference. Information relating to our Code of Business Ethics and Conduct that applies to our senior financial officers is included in Part I, Item 1, and is incorporated herein as reference. Other information required by this item will be contained in our definitive proxy statement to be filed pursuant to Regulation 14A and is incorporated herein by reference.
Item 11. Executive Compensation
Information required by this item will be contained in our definitive proxy statement to be filed pursuant to Regulation 14A and is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information required by this item will be contained in our definitive proxy statement to be filed pursuant to Regulation 14A and is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information required by this item will be contained in our definitive proxy statement to be filed pursuant to Regulation 14A and is incorporated herein by reference.
Item 14. Principal Accountant Fees and Services
Information required by this item will be contained in our definitive proxy statement to be filed pursuant to Regulation 14A and is incorporated herein by reference.

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PART IV
Item 15. Exhibits and Financial Statement Schedules
(a)   (1)