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

o		Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Transition Period from                      to                     

SUPERIOR ENERGY SERVICES, INC.

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.

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

TABLE OF CONTENTS

		Page
PART I
Item 1. Business			1
Item 1A. Risk Factors			10
Item 1B. Unresolved Staff Comments			17
Item 2. Properties			17
Item 3. Legal Proceedings			17
Item 4. Submission of Matters to a Vote of Security Holders			17
Item 4A. Executive Officers of Registrant			18
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities			19
Item 6. Selected Financial Data			21
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			22
Item 7A. Quantitative and Qualitative Disclosures about Market Risk			33
Item 8. Financial Statements and Supplementary Data			35
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			79
Item 9A. Controls and Procedures			79
Item 9B. Other Information			79
PART III
Item 10. Directors, Executive Officers and Corporate Governance			80
Item 11. Executive Compensation			80
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			80
Item 13. Certain Relationships and Related Transactions, and Director Independence			80
Item 14. Principal Accountant Fees and Services			80
PART IV
Item 15. Exhibits, Financial Statement Schedules			81
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

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-

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;

	•		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.

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

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

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

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

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.

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

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.

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;

	•		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.

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,

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

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

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

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.

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.

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

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.

				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.

	•		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

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.

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

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

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

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

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.

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.

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

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

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 3^rd and December 3^rd 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 1^st and December 1^st 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 15^th and June 15^th 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;

	•		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.

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.

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.

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.

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.

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

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

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.

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.

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.

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.

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