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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)


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

		For the fiscal year ended December 31, 2005


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

		For the Transition Period from to

Commission File No. 0-20310

SUPERIOR ENERGY SERVICES, INC.

(Exact name of registrant as specified in its charter)


Delaware		75-2379388
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1105 Peters Road
Harvey, LA		70058
*(Address of principal executive offices)*		*(Zip Code)*

Registrant’s telephone number:		(504) 362-4321

Securities registered pursuant to Section 12(b) of the Act:


Title of each class:		Name of each exchange on which registered:
Common Stock, $.001 Par Value		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes o No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b -2 of the Exchange Act. (Check one):

Large accelerated filer o Accelerated filer o Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

The aggregate market value of the voting stock held by non-affiliates of the registrant at June 30, 2005 based on the closing price on the New York Stock Exchange on that date was $1,416,844,000.

The number of shares of the registrant’s common stock outstanding on February 28, 2006 was 79,732,091.

DOCUMENTS INCORPORATED BY REFERENCE

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

FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains forward-looking statements that are subject to a number of risks and uncertainties. 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 actions, industry trends, 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 such 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. The forward-looking statements are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Numerous factors could cause actual results to differ materially from those in the forward-looking statements, including those described under “Item 1A. Risk Factors” below and elsewhere herein.

PART I

Item 1. Business

General

We are a leading provider of specialized 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, marine and other oilfield services segments. In recent years, we have expanded geographically so that we now also have a growing presence in select domestic land and international markets. We also own and operate, through our subsidiary SPN Resources, LLC, mature oil and gas properties in the Gulf of Mexico. Our business is organized into five segments consisting of well intervention services, rental tools, marine services, other oilfield services and oil and gas operations. We believe that we are one of the few companies in the Gulf of Mexico capable of providing the services, tools and liftboats necessary to maintain, enhance and extend the life of offshore producing wells, as well as plug and abandonment services at the end of their life cycle. We believe that our ability to provide our customers with multiple services and to coordinate and integrate their delivery allows us to maximize efficiency, reduce lead-time and provide cost-effective solutions for our customers.

SPN Resources acquires mature, shallow water Gulf of Mexico oil and gas properties from our customers. We believe this service provides our customers with an effective way to dispose of older, non-core properties that provides additional utilization for our well intervention and decommissioning services and our platform management business. We use our production-related services to enhance production and, at the end of a property’s economic life, use our assets to plug wells and decommission properties. Since we operate virtually all of the properties we own, we can schedule work to increase our efficiency and the utilization of our assets and services.

Operations

Well Intervention Services. We provide well intervention services that stimulate oil and gas production using platforms or our liftboats rather than through the use of a drilling rig, which we believe provides a cost advantage to our customers. Our well intervention services include coiled tubing, electric wireline, mechanical wireline, pumping and stimulation, artificial lift, well control, snubbing, recompletion, engineering and well evaluation services. We believe we are the leading provider of mechanical wireline services in the Gulf of Mexico with approximately 190 offshore wireline units, 20 land wireline units and 10 dedicated liftboats configured specifically for wireline services. We also perform both permanent and temporary plug and abandonment services and decommissioning services. We are constructing an 880-ton derrick barge to support SPN Resources’ business and to expand our decommissioning services. We expect the barge to be available late in the third quarter of 2006.

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 now have 28 locations in all major staging points in Louisiana and Texas for offshore oil and gas activities in the Gulf of Mexico. Our rental tool segment also has locations domestically in North Louisiana, Oklahoma and Wyoming, and internationally in Venezuela, Trinidad, Mexico, Eastern Canada, the North Sea, the Middle East and West Africa. Our rental tools include pressure control equipment, specialty tubular goods, connecting iron, handling tools, drill pipe, bolting equipment, power swivels, 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 36 liftboats, including 10 liftboats configured specifically for wireline services (included in our well intervention segment) and 26 in our rental fleet with leg-lengths ranging from 145 feet to 250 feet. In June 2005, we sold our 17 rental liftboats in the 105-foot and the 120 to 135-foot classes since we believed they were not core to our production-related services and decommissioning strategies. We are also currently refurbishing a 200-foot class liftboat and anticipate returning it to service during the second quarter of 2006. 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 will reposition some of our larger liftboats to international market areas if opportunities arise.

Other Oilfield Services. We provide a broad range of platform and field management services to the offshore and onshore oil and gas industry, including property management, engineering services, operating labor, transportation, tools and supplies, technical supervision, maintenance, supplemental personnel, and logistics services. We currently provide property management services to approximately 130 offshore facilities in the Gulf of Mexico. We also provide environmental cleaning services, including tank and vessel cleaning and safe vessel entry. We also provide other services, including the manufacture and sale of specialized drilling rig instrumentation, electronic torque and pressure control equipment. Subsequent to year-end, we sold our non-hazardous oilfield waste management business, as it was not core to our production-related services.

Oil and Gas Operations. We acquire mature oil and gas properties in the Gulf of Mexico to provide our customers a cost-effective alternative to the 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, 2005, we had interests in 32 offshore blocks containing 58 structures and approximately 140 producing wells.

For additional industry segment financial information, see note 14 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 operating on the U.S. continental shelf. Sales to Shell accounted for approximately 10% of our total revenue in 2005. In 2004, no customer accounted for more than 10% of revenue and in 2003, sales to one customer accounted for approximately 11% of our total revenue. We do not believe that the loss of any one customer would have a material adverse effect on our revenues. However, our inability to continue to perform services for a number of our large existing customers, if not offset by sales to new or other existing customers could have a material adverse effect on our business and operations.

Competition

We operate in highly competitive areas of the oilfield services industry. The products and services of each of our principal operating segments are sold in highly competitive markets, and our revenues and earnings can be affected by the following factors:

	•		changes in competitive prices;

	•		oil and gas prices and industry perceptions of future prices;

	•		fluctuations in the level of activity by oil and gas producers;

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

Our operations may be adversely affected if our current competitors or new market entrants introduce new products or services with better features, performance, prices or other characteristics than our products and services, or if they would offer to pay more for mature oil and gas properties. Further, if our competitors construct additional liftboats for the Gulf of Mexico market area, it could affect vessel utilization and resulting day rates. Competitive pressures or other factors also may result in significant price competition that could reduce our operating cash flow and earnings. In addition, competition among oilfield service and equipment providers is affected by each provider’s reputation for safety and quality. Although we believe that our reputation for safety and quality service is good, we cannot assure that we will be able to maintain our competitive position.

Health, Safety and Environmental Assurance

We have established health, safety and environmental performance as a corporate priority. Our goal is to be an industry leader in this area by focusing on the belief that all safety and environmental incidents are preventable and an injury-free workplace is achievable by emphasizing correct behavior. We have a company-wide effort to enhance our behavioral safety process and training program and make safety a constant focus of awareness through open communication with all of our offshore and yard employees. In addition, we investigate all incidents with a priority of identifying and implementing the corrective measures necessary to reduce the chance of reoccurrence.

Potential Liabilities and Insurance

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

Government Regulation

Our business is significantly affected by the following:

•

Federal and state laws and other regulations relating to the oil and gas industry;

	•		changes in such laws and regulations; and

	•		the level of enforcement thereof.

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

Regulation of Oil and Gas Production

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

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

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

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

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

Natural Gas Marketing, Gathering and Transportation

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

Certain of our pipeline systems are regulated for safety compliance by the U.S. Department of Transportation, or DOT. Pursuant to the Pipeline Safety Improvement Act of 2002, DOT has implemented regulations intended to increase pipeline operating safety. Among other provisions, the regulations require that pipeline operators implement a pipeline integrity management program that must at a minimum include an inspection of gas transmission pipeline facilities within the next ten years, and at least every seven years thereafter.

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

Federal Regulation of Petroleum

Our sales of oil and gas are not regulated and are at market prices. The price received from the sale of these products is affected by the cost of transporting the products to market. Much of that transportation is through interstate common carrier pipelines. FERC has implemented regulations approving interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may tend to increase the cost of transporting oil and natural gas by interstate pipeline, although the annual adjustments may result in decreased rates in a given year.

Environmental Regulations

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

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

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

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

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

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

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

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

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

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

Maritime Employees

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

Employees

As of February 28, 2006, we had approximately 3,200 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 76 facilities located in Louisiana, Texas, Oklahoma, Colorado, Wyoming, Venezuela, Australia, Trinidad, Mexico, the North Sea, Eastern Canada, the Middle East and West Africa to support our operations. We believe that all of our leases are at competitive or market rates and do not anticipate any difficulty in leasing suitable additional space as may be needed or extending terms when our current leases expire.

Oil and Natural Gas Reserves

The following table presents our estimated net proved oil and natural gas reserves at December 31, 2005 and 2004 and estimated future net revenues and cash flows attributable thereto. Our proved reserves for 2005 and 2004 were estimated by DeGolyer and MacNaughton, independent petroleum engineers. Our proved reserves at December 31, 2003 were not significant.


	As of December 31,
	2005		2004
Total estimated net proved reserves:
Oil (Mbbls)		9,103		9,120
Natural gas (Mmcf)		23,688		29,380
Total (Mboe) (1)		13,051		14,017
Net proved developed reserves (4):
Oil (Mbbls)		7,554		7,731
Natural gas (Mmcf)		21,703		25,542
Total (Mboe) (1)		11,171		11,988
Estimated future net revenues before income taxes (in thousands) (2)	$	441,550	$	285,437
Standardized measure of discounted future net cash flows (in thousands) (3)	$	205,105	$	136,507


(1)		Barrel of oil equivalents (boe) are determined using the ratio of 6 thousand cubic feet (mcf) of natural gas to 1 barrel (bbl) of oil or condensate. Mboe, mbbls and mmcf mean a thousand boe, a thousand bbl and a million cubic feet, respectively.

(2)		The December 31, 2005 amount was estimated by DeGolyer and MacNaughton using a period-end crude New York Mercantile Exchange (NYMEX) price of $61.04 per bbl for oil and a NYMEX gas price of $9.44 per million British Thermal units for natural gas, and price differentials provided by us. The December 31, 2004 amount was also estimated by DeGolyer and MacNaughton using a period-end crude NYMEX price of $43.46 per bbl for oil and a Henry Hub gas price of $6.19 per million British Thermal units for natural gas, and price differentials provided by us. Net revenues as they appear in the table are defined as gross revenue, less production taxes, operating expenses and capital costs.

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

(4)		Net proved developed non-producing reserves at December 31, 2005 were 3,713 mbbls (41% of total net proved oil reserves) and 16,469 mmcf (70% of total net proved gas reserves). Net proved undeveloped reserves as of December 31, 2005 were 1,549 mbbls (17.0% of total net proved oil reserves) and 1,985 mmcf (8.4% of total net proved gas reserves).

Since January 1, 2005 no crude oil or natural gas reserve information has been filed with, or included in any report to any federal authority or agency other than the SEC and the Energy Information Administration (“EIA”). The Company files Form 23, including reserve and other information with the EIA.

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

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

Productive Wells Summary

The following table presents our ownership at December 31, 2005, of productive oil and natural gas wells. Productive wells consist of producing wells and wells capable of production. Thirteen gross oil wells and two gross natural gas wells have dual completions. In the table, “gross” refers to the total wells in which we own an interest and “net” refers to the sum of fractional interests owned in gross wells.


	Total
	Productive Wells
	Gross		Net
Oil		293.00		286.10
Natural gas		53.00		46.33

Total		346.00		332.43

As of December 31, 2005, only approximately 140 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, 2005 relating to acreage held by us. Developed acreage is assigned to productive wells.


	Gross		Net
	Acreage		Acreage
Developed		133,387		110,458
Undeveloped		5,760		5,760

Total		139,147		116,218

Leases covering 100% of our undeveloped net acreage will expire in 2006.

Drilling Activity

The following table shows our drilling activity for the years ended December 31, 2005, 2004 and 2003. 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.


	2005				2004				2003
	Gross		Net		Gross		Net (1)		Gross		Net
Development Wells:
Productive		1.00		0.50		3.00		0.06		0.00		0.00
Non-productive		0.00		0.00		0.00		0.00		0.00		0.00

Total		1.00		0.50		3.00		0.06		0.00		0.00


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

Costs Incurred in Oil and Natural Gas Activities

The following table displays certain information regarding the costs incurred associated with finding, acquiring and developing our proved oil and natural gas reserves for the years ended December 31, 2005, 2004 and 2003 (in thousands). We acquired our first property in December 2003.


	Years Ended December 31,
	2005		2004		2003
Acquisition of properties — proved	$	9,015	$	81,356	$	5,041
Development costs		19,867		4,707		—

Total costs incurred	$	28,882	$	86,063	$	5,041

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


	2005			2004			2003
Proved properties	$	28,882		$	86,063		$	5,041
Accumulated depreciation, depletion and amortization		(18,065	)		(7,156	)		(131	)

	$	10,817		$	78,907		$	4,910

Intellectual Property

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

Other Information

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

Item 1A. Risk Factors

There are many factors that affect our business and the results of our operations, many of which are beyond our control. If any of the following risks develop into actual events, our business, financial condition, results of operations or cash flows could be adversely affected and the trading price of our common stock could decline.

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

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

	•		oil and gas prices and industry perceptions of future price levels;

	•		the cost of exploring for, producing and delivering oil and gas;

	•		the ability of oil and gas companies to generate capital;

	•		the sale and expiration dates of offshore leases;

	•		the discovery rate of new oil and gas reserves; and

	•		local and international political and economic conditions.

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

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 us or 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.

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. In addition, we acquire these properties without obtaining bonds, other than as required by MMS to secure the plugging and abandonment obligations. Acquisitions of these properties require an assessment of a number of factors beyond our control, including estimates of recoverable reserves, future oil and gas prices, operating costs and potential environmental and plugging and abandonment liabilities. These assessments are complex and inherently imprecise, and, with respect to estimates of oil and gas reserves, require significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. In addition, since these properties are typically older and near the end of their economic lives, 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.

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 may not be able to obtain future insurance coverage comparable with that of prior years, thus putting us at a greater risk of loss due to severe weather conditions. We are also likely to experience increased cost for available insurance coverage which will likely impose higher deductibles and limit maximum aggregate recoveries for certain perils such as hurricane related windstorm damage or loss. Any significant uninsured losses could have a material adverse effect on our financial position, results of operations and cash flows.

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 depend on significant customers.

We derive a significant amount of our revenue from a small number of major and independent oil and gas companies. In 2005, Shell accounted for approximately 10% of our total revenue. We did not have a single customer account for more than 10% of our total revenue in 2004 and in 2003, sales to a single customer accounted for approximately 11% of our total revenue. Our inability to continue to perform services for a number of our large existing customers, if not offset by sales to new or other existing customers could have a material adverse effect on our business and operations.

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

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

	•		fires;

	•		explosions, blowouts, and cratering;

	•		well blowouts;

	•		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 vessels are covered by provisions of the Jones Act, the Death on the High Seas Act and general maritime law. These laws make the liability limits established by state workers’ compensation laws inapplicable to these employees and instead permit

them or their representatives to pursue actions against us for damages for job-related injuries. In such actions, there is generally no limitation on our potential liability.

Any litigation arising from a catastrophic occurrence involving our services, equipment or oil and gas production operations could result in large claims for damages. The frequency and severity of such incidents affect our operating costs, insurability and relationships with customers, employees and regulators. Any increase in the frequency or severity of such incidents, or the general level of compensation awards with respect to such incidents, could affect our ability to obtain projects from oil and gas companies or insurance. We maintain several types of insurance to cover liabilities arising from our services, including onshore and offshore non-marine operations, as well as marine vessel operations. These policies include primary and excess umbrella liability policies with limits of $50 million dollars per occurrence, 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 these operations are $50 million per occurrence for well control incidents, and the limit is also $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 expect very substantial increases in our costs of insurance, as well as increased deductibles and self-insured retentions. We also expect that upon renewal, this property insurance coverage will be subject to an annual loss limit of $35 million in the aggregate with respect to property damage caused by hurricanes and named storms. We are seeking alternatives to allow us to increase this annual aggregate limit. 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 may not be able to obtain future insurance coverage comparable with that of prior years, thus putting us at a greater risk of loss due to severe weather conditions. In addition, we are likely to experience increased cost for available insurance coverage which may impose higher deductibles and limit maximum aggregate recoveries for certain perils such as hurricane related windstorm damage or loss. As a result, we may be forced to modify our risk management program in response to changes in the insurance market, including increased risk retention. Any significant uninsured losses could have a material adverse effect on our financial position, results of operations and cash flows.

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

	•		the presence of unanticipated pressure or irregularities in formations;

	•		equipment failures or accidents;

	•		adverse weather conditions;

	•		compliance with governmental requirements; and

	•		shortages or delays in obtaining drilling rigs or in the delivery of equipment and services.

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

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

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

	•		worldwide or regional demand for energy, which is affected by economic conditions;

	•		the domestic and foreign supply of oil and gas;

	•		weather conditions;

	•		domestic and foreign governmental regulations;

	•		political conditions in oil and gas producing regions;

	•		the ability of members of the Organization of Petroleum Exporting Countries to agree upon and maintain oil prices and production levels; and

	•		the price and availability of alternative fuel sources.

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

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

We are subject to market risk exposure in the pricing applicable to our oil and gas production. Considering the historical and continued volatility and uncertainty of prices received for oil and gas production, we have and 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 level of domestic production and imports of oil and gas;

	•		the proximity of gas production to gas pipelines;

	•		the availability of pipeline capacity;

	•		the demand for oil and natural gas by utilities and other end users;

	•		the availability of alternate fuel sources;

	•		state and federal regulation of oil and gas marketing; and

	•		federal regulation of gas sold or transported in interstate commerce.

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

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

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

	•		lack of sufficient executive-level personnel;

	•		increased administrative burden; and

	•		increased logistical problems common to large, expansive operations.

If we do not manage these potential difficulties successfully, our operating results could be adversely affected.

Our inability to control the inherent risks of acquiring businesses could adversely affect our operations.

Acquisitions have been and we believe will continue to be a key element of our business strategy. We cannot assure you that we will be able to identify and acquire acceptable acquisition candidates on terms favorable to us in the future. We may be required to incur substantial indebtedness to finance future acquisitions and also may issue equity securities in connection with such acquisitions. Such additional debt service requirements may impose a significant burden on our results of operations and financial condition. The issuance of additional equity securities could result in significant dilution to our stockholders. We cannot assure you that we will be able to successfully consolidate the operations and assets of any acquired business with our own business. Acquisitions may not perform as expected when the acquisition was made and may be dilutive to our overall operating results. In addition, our management may not be able to effectively manage our increased size or operate a new line of business.

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

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

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

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

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

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

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

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

We are unable to predict the level of enforcement of existing laws and regulations, how such laws and regulations may be interpreted by enforcement agencies or court rulings, or whether additional laws and regulations will be adopted. We are also unable to predict the effect that any such events may have on us, our business, or our financial condition.

A terrorist attack or armed conflict could harm our business.

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

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

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

	•		political, social and economic instability;

	•		potential seizure or nationalization of assets;

	•		increased operating costs;

	•		modification or renegotiating of contracts;

	•		import-export quotas;

	•		currency fluctuations; and

	•		other forms of government regulation which are beyond our control.

Our operations have not yet been affected to any significant extent by such conditions or events, but as our international operations expand, the exposure to these risks will increase. We could, at any one time, have a significant amount of our revenues generated by operating activity in a particular country. Therefore, our results of

operations could be susceptible to adverse events beyond our control that could occur in the particular country in which we are conducting such operations. We anticipate that our contracts to provide services internationally will generally provide for payment in U.S. dollars and that we will not make significant investments in foreign facilities. To the extent we make investments in foreign facilities or receive revenues in currencies other than U.S. dollars, the value of our assets and our income could be adversely affected by fluctuations in the value of local currencies.

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

	•		the awarding of contracts to local contractors;

	•		the employment of local citizens; and

	•		the establishment of foreign subsidiaries with significant ownership positions reserved by the foreign government for local citizens.

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

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

The delivery of our products and services require personnel with specialized skills and experience. As a result, our ability to remain productive and profitable will depend upon our ability to employ and retain skilled workers. In addition, our ability to expand our operations depends in part on our ability to increase the size of our skilled labor force. The demand for skilled workers in the Gulf Coast region is high, and the supply is limited. In addition, although our employees are not covered by a collective bargaining agreement, the marine services industry has been targeted by maritime labor unions in an effort to organize Gulf of Mexico employees. A significant increase in the wages paid by competing employers or the unionization of our Gulf of Mexico employees could result in a reduction of our skilled labor force, increases in the wage rates that we must pay or both. If either of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Information on properties is contained in Item 1 of this Form 10-K and in note 13 to our consolidated financial statements included in Item 8 of this Form 10-K.

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 60, 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 56, 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 51, 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 48, has served as one of our Executive Vice Presidents since September 2004. He served as one of our Vice Presidents from June 2003 until September 2004. From July 1999 until June 2003, Mr. Bernard served as the Chief Financial Officer of our wholly-owned subsidiary International Snubbing Services, L.L.C. and its predecessor company.

L. Guy Cook, III, age 37, has served as one of our Executive Vice Presidents since September 2004. He has also served as a Vice President of our wholly owned subsidiary Superior Energy Services, L.L.C. and its predecessor company since August 2000. He served as our Director of Investor Relations from April 1997 to February 2000 and was also responsible for integrating our acquisitions during that time.

James A. Holleman, age 48, has served as one of our Executive Vice Presidents since September 2004. He served as one of our Vice Presidents from July 1999 to September 2004. Since July 1999, Mr. Holleman has served as a Vice President of Superior Energy Services, L.L.C. From 1994 until July 1999, he served as the Chief Operating Officer of Cardinal Services, Inc., which we acquired in July 1999 and is the predecessor to Superior Energy Services, L.L.C.

Gregory L. Miller, age 48, has served as one of our Executive Vice Presidents since September 2004. He also serves as the President of our wholly-owned subsidiary SPN Resources, LLC, which position he has held since April 2003. From January 1991 to April 2003, Mr. Miller served as President and Chief Executive Officer of Optimal Energy, Inc.

Danny R. Young, age 50, has served as one of our Executive Vice Presidents since September 2004. He has also served as Vice President of Health, Safety and Environment and Corporate Services of Superior Energy Services, L.L.C. from January 2002 to May 2005. Prior to joining us, Mr. Young worked for 22 years at BP Amoco.

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
2004

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

2005

	First Quarter	$	19.75	$	14.58
	Second Quarter		18.46		13.71
	Third Quarter		24.10		17.64
	Fourth Quarter		23.98		17.33

As of February 28, 2006, there were 79,732,091 shares of our common stock outstanding, which were held by 127 record holders.

Dividend Information

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

Equity Compensation Plan Information

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

Issuer Purchases of Equity Securities

None.

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,
	2005			2004			2003		2002		2001
Revenues	$	735,334	(1)	$	564,339	(2)	$	500,625	$	443,147	$	449,042	(3)
Income from operations		125,603			76,289			67,343		57,021		104,953
Income before cumulative effect of change in accounting principle		67,859			35,852			30,514		21,886		51,187
Cumulative effect of change in accounting principle, net		—			—			—		—		2,589	(4)
Net income		67,859			35,852			30,514		21,886		53,776
Net income before cumulative effect of change in accounting principle per share:
Basic		0.87			0.48			0.41		0.30		0.74
Diluted		0.85			0.47			0.41		0.30		0.73
Net income per share:
Basic		0.87			0.48			0.41		0.30		0.78
Diluted		0.85			0.47			0.41		0.30		0.77
Total assets		1,097,250			1,003,913			832,863		727,620		665,520
Long-term debt, less current portion		216,596			244,906			255,516		256,334		269,633
Decommissioning liabilities, less current portion		107,641			90,430			18,756		—		—
Stockholders’ equity		524,374			433,879			368,129		335,342		269,576


(1)		In the year ended December 31, 2005, our subsidiary, SPN Resources, LLC, acquired additional oil and gas properties through the acquisition of interests in 3 offshore Gulf of Mexico leases. Under the terms of the transaction, we received approximately $3.7 million in cash, acquired the properties and assumed the related decommissioning liabilities.

(2)		In the year ended December 31, 2004, our subsidiary, SPN Resources, LLC, acquired additional oil and gas properties through the acquisition of interests in 19 offshore Gulf of Mexico leases. Under the terms of these transactions, we paid approximately $10.7 million (net of approximately $5.0 million cash received), acquired the properties and assumed the related decommissioning liabilities.

(3)		In the year ended December 31, 2001, we made five acquisitions for $108 million in initial aggregate consideration, of which $2 million was paid with common stock. These acquisitions have been accounted for as purchases, and the results of operations have been included from the respective company’s acquisition date.

(4)		In 2001, we changed depreciation methods from the straight-line method to the units of production method on our liftboat fleet. The cumulative effect of this change in accounting principle on prior years resulted in an increase in net income of $2.6 million, net of income taxes of $1.7 million.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our consolidated financial statements included elsewhere in this Annual Report on Form 10-K. The following information contains forward-looking statements, which are subject to risks and uncertainties. Should one or more of these risks or uncertainties materialize, our actual results may differ from those expressed or implied by the forward-looking statements. See “Forward-Looking Statements” at the beginning of this Annual Report on Form 10-K.

Executive Summary

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

The primary factors driving our performance in 2005 were (1) increased customer spending levels on finding and replacing oil and gas reserves due to high commodity prices; (2) increased customer focus on replacing reserves through production-enhancement projects in existing wells; and (3) the active hurricane season, which disrupted a strong Gulf of Mexico market, but created incremental long-term demand for our products and services.

In 2005, activity across all segments increased throughout the year, particularly in the Gulf of Mexico. However, the extraordinarily active hurricane season – highlighted by damage caused by Hurricanes Katrina and Rita – disrupted most Gulf of Mexico-based well intervention service and rental tool activity for almost three months following the storms.

By mid-November, pre-storm Gulf activity levels resumed for well intervention services and rental tools and by year-end demand for most services and tools were exceeding those levels. The marine segment participated in post-storm damage assessment and construction support projects throughout the fourth quarter. By the end of the year, liftboat demand continued to grow due to the post-hurricane construction and repair work, coupled with well intervention work that was deferred prior to the storms. This led to unprecedented dayrates for liftboats as year-end dayrates were 50% higher than rates in August 2005, and 30% higher than dayrates we were generating during the second and third quarters of 2001 when prior peak dayrates were established. Also, for the first time in several years, we were able to achieve meaningful price increases for some of our well intervention services. Financial performance for services has traditionally been driven by volume, or utilization, while pricing improvement has been difficult to achieve. However, pent-up demand and incremental work created by hurricane damage have allowed us to raise prices on some services by as much as 20%.

The active hurricane season also caused significant damage to the industry’s Gulf of Mexico infrastructure. Our participation in the Gulf of Mexico repair efforts include project management; marine and well control engineering; relief well planning, supervision and execution; well intervention planning; offshore supervision and offshore site and activity management; well abandonment; and specialty equipment and tools. In addition, we will provide our liftboats, well intervention services and rental tools to many more projects that we are not managing.

Our oil and gas production remained largely shut-in following the hurricanes due to hurricane damage. During the fourth quarter, we were repairing our properties and awaiting repairs to pipelines owned by third parties. Average production during the second quarter of 2005, prior to the active hurricane season, was approximately 7,200 barrels of oil equivalent (“boe”) per day. However, in the third and fourth quarters, production averaged approximately 4,600 boe per day and 1,100 boe per day, respectively. All of our production is expected to be restored by the end of the first quarter of 2006.

In our other geographic market areas, we benefited from increased levels of customer spending driven by high commodity prices. International revenue was a record $99.3 million, primarily due to continued expansion of our rental tools business in markets such as the North Sea, Venezuela, the Middle East and West Africa and well intervention activity in Australia, Egypt and Venezuela. Approximately 55% of our international revenue is derived from the rental tools segment. The remainder is derived from well intervention services such as hydraulic workover, sidetrack drilling and well control services.

Domestically, we aggressively expanded our rentals of drill pipe, ancillary tubulars, handling tools, stabilizers, and drill collars to market areas in Arkansas, Louisiana, Texas, Oklahoma and Wyoming. Toward the end of the year we expanded our well intervention services in these market areas. Drilling rig counts and production-related spending are expected to grow domestically on land, and we believe we can successfully expand our presence in these market areas. As a result, demand should continue at high levels in the markets in which we compete due to the current high level of commodity prices and our customers’ focus on rapidly replacing oil and gas reserves from reservoirs that deliver the highest returns for the least amount of risk.

In the Gulf of Mexico, activity is expected to remain robust. In the deepwater Gulf, large energy producers continue to fund exploration and drilling programs in an effort to locate and produce large reservoirs of oil and gas. The shallow water Gulf is more mature, providing production-enhancement opportunities for smaller operators.

The mature nature of the shallow water Gulf market should benefit our newly constructed derrick barge – which is expected to be available during the third quarter of 2006 – and increase our ability to acquire additional mature properties. We expect decommissioning activity to accelerate as shallow water wells become uneconomical and platforms must be removed. Mature wells often require significant intervention to enhance, extend and maintain production. The costs of this intervention, coupled with the additional risks associated with hurricanes, may lead many energy producers to re-assess the costs and benefits of owning these mature properties.

Well Intervention Segment

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

Revenue and operating income were 17% and 20% higher, respectively, as compared to 2004 despite significant hurricane-related downtime in the Gulf of Mexico. This downtime was more than offset by strong Gulf of Mexico activity levels during the first half of the year, especially for services such as coiled tubing, mechanical wireline and electric line services, and improved pricing for many services toward the end of the year. In addition, year-over-year performance improved significantly for well control and hydraulic workover services in non-Gulf of Mexico markets.

Rental Tools Segment

The rental tools segment is capital intensive with high operating margins as a result of relatively low operating costs. The largest fixed cost is typically depreciation as there is little labor associated with our rental tools business. Pricing generally does not fluctuate and financial performance is a function of changes in volume rather than pricing.

Revenue increased 43% and operating income increased 68% over 2004. The biggest increases in revenue and operating income were from the rentals of drill pipe, particularly rentals in international markets, as well as rentals of on-site accommodations and handling tools. Rentals outside the Gulf of Mexico represented more than 60% of this segment’s total revenue in 2005.

Marine Segment

The 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, our gross margin percentages were 40% in the first quarter, 32% in the second quarter, 36% in the third quarter and 62% in the fourth quarter.

Revenue increased 25% and operating income increased more than 320% over 2004. Liftboat dayrates and utilization steadily increased during the first and second quarters of the year. Activity levels were improving in August prior to Hurricanes Katrina and Rita. Following the storms, dayrates increased to record levels and liftboat utilization averaged approximately 90% during the fourth quarter as our liftboats were used to support our customers’ damage assessment and construction projects.

We sold 17 of our smaller liftboats during the second quarter. These liftboats had lower gross profit percentages than our fleet of larger liftboats.

Other Oilfield Services

More than half of this segment’s revenues are derived from our offshore platform and property management business, a labor-intensive business with low margins. Environmental services, such as dockside vessel and tank cleaning and non-hazardous oilfield waste treatment, comprise most of the other revenue in this segment.

Revenues increased 9% over 2004, but our operating loss increased to $6.8 million from $2.6 million in 2004. This segment’s operating loss would have decreased by approximately $4.9 million if we did not incur non-recurring, non-cash charges related to the sale of our oil spill response assets and the reduction in value of our non-hazardous oilfield waste treatment business as a result of our intent to sell the business. The segment’s customer base operates in the Gulf of Mexico and along the Gulf Coast. The 2005 hurricane season disrupted drilling activity during the last half of the year, adversely impacting production and drilling activity, the primary drivers for our offshore platform and property management business and our environmental businesses, respectively. Also, several of our Gulf Coast facilities suffered hurricane-related damage, limiting our environmental service capabilities during the third and fourth quarters.

Oil and Gas Segment

Through our subsidiary SPN Resources, LLC, we acquire, manage and decommission mature properties in the shallow waters of the Gulf of Mexico. As of December 31, 2005, we had interests in 32 offshore blocks containing 58 structures and approximately 140 producing wells.

The main objective of this business segment is to provide additional opportunities for our products and services, especially during cyclical and seasonal slower periods. Because of the 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 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 relatively high because of the amount of well intervention service work required to enhance, maintain and extend production for mature properties. The gross operating margin is also a function of oil and gas prices.

Revenues were 113% higher and operating income was 76% higher than 2004. Although we benefited from higher commodity prices and more production as a result of properties we acquired in 2004, approximately 744,000 boe of production was deferred as a result of extensive damage caused by the active hurricane season. We did not suffer any permanent damage to wells, and we expect our production to be fully-restored by the end of the first 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 the portrayal of our financial condition and results of operations and requires us to make difficult, subjective or complex judgments or estimates about matters that are uncertain. We believe that the following are the critical accounting policies and estimates used in the preparation of our consolidated financial statements. In addition, there are other items within our consolidated financial statements that require estimates but are not deemed critical as defined in this paragraph.

Long-Lived Assets. We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of any such asset may not be recoverable. We record impairment losses on long-lived assets, including oil and gas properties, used in operations when the estimated cash flows to be generated by those assets are less than the carrying amount of those items. Our cash flow estimates are based upon, among other things, historical results adjusted to reflect our best estimate of future market rates, utilization levels, operating performance, and with respect to our oil and gas properties, future oil and natural gas sales prices, an estimate of the ultimate amount of recoverable oil and natural gas reserves that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas and other factors. Our estimates of cash flows may differ from actual cash flows due to, among other things, changes in economic conditions or changes in an asset’s operating performance. If the sum of the cash flows is less than the carrying value, we recognize an impairment loss, measured as the amount by which the carrying value exceeds the fair value of the asset. The net carrying value of assets not fully recoverable is reduced to fair value. Our estimate of fair value represents our best estimate based 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. We recognize revenue when services or equipment are provided and collectibility is reasonably assured. Services and rentals are generally provided based on fixed or determinable priced purchase orders or contracts with customers. We contract for marine, well intervention and environmental projects either on a day rate or turnkey basis, with a majority of our projects conducted on a day rate basis. Our rental tools are rented on a day rate basis, and revenue from the sale of equipment is recognized when the equipment is shipped. We 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 up to certain levels for losses related to workers’ compensation, protection and indemnity, general liability, property damage, and group medical. With the recent tightening in the insurance markets, we have elected to retain more risk by increasing our self-insurance. We accrue for these liabilities based on estimates of the ultimate cost of claims incurred as of the balance sheet date. We regularly review our estimates of reported and unreported claims and provide for losses through reserves. We also have an actuary review our estimates for 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, health care costs and future inflation rates are different from our estimates. Although we believe adequate reserves have been provided for expected liabilities arising from our self-insured obligations, and we believe that we maintain adequate reinsurance coverage, we cannot assure that such coverage will adequately protect us against liability from all potential consequences.

Oil and Gas Properties. 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 value (including an estimated profit) to plug and abandon wells, abandon the pipelines, decommission and remove the platforms and clear the sites, and use that estimate to record our proportionate share of the decommissioning liability. In estimating the decommissioning liabilities, we perform detailed estimating procedures, analysis and engineering studies. Whenever practical, we will utilize the services of our subsidiaries to perform well abandonment and decommissioning work. When these services are performed by our subsidiaries, all recorded intercompany revenues and expenses are eliminated in the consolidated financial statements. The recorded decommissioning liability associated with a specific property is fully extinguished when the property is completely abandoned. The liability is first reduced by all cash expenses incurred to abandon and decommission the property. If the liability exceeds (or is less than) our out-of-pocket costs, the difference is reported as income (or loss) in the period in which the work is performed. We review the adequacy of our decommissioning liability whenever indicators suggest that the estimated cash flows underlying the liability have changed materially. The timing and amounts of these cash flows are subject to changes in the energy industry environment and may result in additional liabilities recorded, which in turn would increase the carrying values of the related properties.

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

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

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

Comparison of the Results of Operations for the Years Ended December 31, 2005 and 2004

For the year ended December 31, 2005, our revenues were $735.3 million resulting in net income of $67.9 million or $0.85 diluted earnings per share. For the year ended December 31, 2004, revenues were $564.3 million and net income was $35.9 million or $0.47 diluted earnings per share. We experienced higher revenue and gross margin in all our segments, especially our rental tools, oil and gas and well intervention segments as activity levels increased. However, the extraordinarily active hurricane season disrupted most of our activity for several months following Hurricanes Katrina and Rita.

The following table compares our operating results for the years ended December 31, 2005 and 2004. Gross margin is calculated by subtracting cost of services from revenue for each of our five business segments. Oil and gas eliminations represent products and services provided to the oil and gas segment by the Company’s four other segments.


	Revenue									Gross Margin
	2005			2004			Change			2005		%			2004		%			Change

Well Intervention	$	248,576		$	211,820		$	36,756		$	106,242		43	%	$	89,755		42	%	$	16,487
Rental Tools		243,536			170,064			73,472			160,974		66	%		112,711		66	%		48,263
Marine		87,267			69,808			17,459			39,278		45	%		20,227		29	%		19,051
Other Oilfield Services		91,033			83,870			7,163			19,729		22	%		16,077		19	%		3,652
Oil and Gas		78,911			37,008			41,903			33,107		42	%		15,461		42	%		17,646
Less: Oil and Gas Elim		(13,989	)		(8,231	)		(5,758	)		—		—			—		—			—

Total	$	735,334		$	564,339		$	170,995		$	359,330		49	%	$	254,231		45	%	$	105,099

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

Well Intervention Segment

Revenue for our well intervention segment was $248.6 million for the year ended December 31, 2005, as compared to $211.8 million for 2004. This segment’s gross margin percentage increased slightly to 43% in 2005 from 42% in 2004. We experienced higher revenue for almost all of our services as production-related activity improved in the Gulf of Mexico, particularly for the well control, hydraulic workover, coiled tubing and wireline services. Activity levels declined in the months following Hurricanes Katrina and Rita, but pre-storm demand levels returned near the end of the year.

Rental Tools Segment

Revenue for our rental tools segment for the year ended December 31, 2005 was $243.5 million, a 43% increase over 2004. The gross margin percentage remained unchanged at 66% for the years ended December 31, 2005 and 2004. We experienced significant increases in revenue from our on-site accommodations, drill pipe and accessories and stabilizers. The increases are primarily the result of significant increases in activity in the Gulf of Mexico, as well as our international and domestic expansion efforts. Although our rental tools segment was negatively impacted from Hurricanes Katrina and Rita in August and September of 2005, activity levels surpassed pre-storm levels for most of our rental tools by the end of the year. Our international revenue for the rental tools segment has increased 108% to approximately $53.6 million for the year ended December 31, 2005 from 2004. Our biggest improvements were in the North Sea, Trinidad, Venezuela and Mexico.

Marine Segment

Our marine segment revenue for the year ended December 31, 2005 increased 25% over 2004 to $87.3 million. The gross margin percentage for the year ended December 31, 2005 increased to 45% from 29% for 2004. The year ended December 31, 2005 includes only five months of rental activity from the 105-foot and the 120 to 135-foot class liftboats. These 17 rental liftboats were sold effective June 1, 2005. The increase in revenue is caused by increased utilization of our fleet’s remaining larger liftboats at higher dayrates partially offset by fewer liftboats generating revenue for seven months of 2005. The increase in the gross margin percentage is also caused by increased demand and the sale of our lower margin rental liftboats. The fleet’s average dayrate increased 47% to approximately $9,223 in the year ended December 31, 2005 from $6,295 in 2004. Increased demand as well as the sale of the smaller liftboats also contributed to the increase in average dayrates. The fleet’s average utilization increased to approximately 78% for the year ended December 31, 2005 from 72% in 2004. Our liftboat fleet experienced strong increases in demand and pricing in the fourth quarter as liftboats were needed for the large amount of construction and repair work in the Gulf of Mexico as a result of hurricane damage.

Other Oilfield Services Segment

Revenue from our other oilfield services segment for the year ended December 31, 2005 was $91.0 million, a 9% increase over the $83.9 million in revenue for 2004. The gross margin percentage increased to 22% in the year ended December 31, 2005 from 19% in 2004. The revenue increase is primarily due to increased demand for our field management and waste disposal services. The increase in the segment’s gross margin percentage is due to the increased demand as well as cost saving efforts in our waste disposal services. This segment incurred an operating loss of approximately $6.8 million, which includes approximately $2.1 million of storm-related general and administrative expenses primarily due to damage to its equipment and facilities from Hurricanes Katrina and Rita and $4.9 million of losses as the result of our decision to sell-off our oil spill response inventory and equipment and our non-hazardous waste disposal service business.

Oil and Gas Segment

Oil and gas revenues were $78.9 million in the year ended December 31, 2005 as compared to $37.0 million in 2004. The increase in revenue is primarily the result of production from South Pass 60, which was acquired in July 2004, and production from West Delta 79/86, which was

acquired in December 2004. We also acquired Galveston 241/255 and High Island A-309 in late-July 2005. In the year ended December 31, 2005, production was approximately 1,794,000 boe as compared to approximately 918,000 boe in 2004. The gross margin percentage remained unchanged at 42% for the years ended December 31, 2005 and 2004. The oil and gas segment was affected by significant amounts of curtailed production resulting from the active hurricane seasons the past two years resulting in deferred production as a result of Hurricanes Katrina and Rita in 2005 of approximately 744,000 boe and as a result of Hurricane Ivan in 2004 of approximately 347,000 boe.

Depreciation, Depletion, Amortization and Accretion

Depreciation, depletion, amortization and accretion increased to $89.3 million in the year ended December 31, 2005 from $67.3 million in 2004. The increase is primarily a result of depletion and accretion related to our oil and gas properties from both increased production and acquisitions of oil and gas properties. The increase also results from the depreciation associated with our 2005 and 2004 capital expenditures primarily in the rental tools segment.

General and Administrative

General and administrative expenses increased to $141.0 million for the year ended December 31, 2005 from $110.6 million in 2004. Of this increase, $5.5 million is the result of storm-related costs from Hurricanes Katrina and Rita in the third and fourth quarters of 2005 including $2.1 million in equipment and facility losses and repairs, $2.0 million in relief aid to more than 560 employees affected by the hurricanes and $1.4 million in storm-related payroll expenses, temporary lodging and miscellaneous expenses. The remaining increase was primarily related to increased payroll and bonus expenses, increased insurance costs and expenses as a result of our growth, oil and gas acquisitions and geographic expansion.

Reduction in Value of Assets

During the year ended December 31, 2005, we reduced the value of two of our mature oil and gas properties by approximately $2.1 million, thereby removing the reserve balance associated with these wells. The wells were deemed to be uneconomical to further produce as a result of the estimated costs associated with maintaining production.

Our oil spill containment boom manufacturing facility suffered damage from Hurricane Katrina and experienced difficulty in resuming normal business operations. As a result, we elected not to reopen this manufacturing facility and sell the remaining oil spill containment boom inventory. We reduced the value of the assets of this business (which consist primarily of inventory and property and equipment) by approximately $1.1 million to the estimated net realizable value.

In the first quarter of 2006, we sold our non-hazardous oilfield waste subsidiary, Environmental Treatment Team, L.L.C. (ETT) for approximately $18.7 million in cash. We reduced the net asset value of ETT by $3.8 million in 2005 to its approximate sales price.

Gain on Sale of Liftboats

Effective June 1, 2005, we sold all of our rental liftboats with leg-lengths from 105 feet to 135 feet for $19.8 million in cash (exclusive of costs to sell), which resulted in a gain of $3.5 million.

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

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

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


	Revenue								Gross Margin
	2004			2003		Change			2004		%			2003		%			Change

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

Total	$	564,339		$	500,625	$	63,714		$	254,231		45	%	$	211,018		42	%	$	43,213

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

Well Intervention Segment

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

Rental Tools Segment

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

Marine Segment

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

Other Oilfield Services Segment

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

Oil and Gas Segment

Oil and gas revenues were $37.0 million and the gross margin percentage was 42% for the year ended December 31, 2004, compared to revenues of $0.7 million and gross margin percentage of 55% for the year ended December 31, 2003. The increase in revenue is due to the fact that our oil and gas segment began in December

2003 and has benefited from the South Pass 60 acquisition completed in July 2004. The segment was negatively impacted by Hurricane Ivan which shut-in or curtailed production from the South Pass 60 field beginning in mid-September 2004 through late December 2004.

Depreciation, Depletion, Amortization and Accretion

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

General and Administrative

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

Liquidity and Capital Resources

In the year ended December 31, 2005, we generated net cash from operating activities of $158.4 million as compared to $91.3 million in 2004. Our primary liquidity needs are for working capital, capital expenditures, debt service and acquisitions. Our primary sources of liquidity are cash flows from operations and borrowings under our revolving credit facility. We had cash and cash equivalents of $54.5 million at December 31, 2005 compared to $15.3 million at December 31, 2004.

We made $125.2 million of capital expenditures during the year ended December 31, 2005, of which approximately $68.5 million was used to expand and maintain our rental tool equipment inventory. We also made $19.7 million of capital expenditures in our oil and gas segment and $32.8 million of capital expenditures, inclusive of $6.7 million in progress payments made on the crane as noted below and $5.6 million for the purchase of a 200-foot class liftboat which we were previously operating, to expand and maintain the asset base of our well intervention, marine and other oilfield services segments. In addition, we made $4.2 million of capital expenditures on construction and improvements to our facilities.

In March 2005, we contracted to construct an 880-ton derrick barge to support our decommissioning operations on the Outer Continental Shelf. The contracts are for the construction of a 350-foot barge and crane for a price of approximately $23 million. This amount does not include any future change orders, barge outfitting or mobilization costs. Progress payments were made on the crane in accordance with the terms set forth in the contract. Letters of credit are due on the barge based on contract milestones. The contract price for the barge will be payable upon its delivery and acceptance. We expect the barge to be available in the Gulf of Mexico late in the third quarter of 2006. We intend to utilize it to remove platforms and structures owned by our subsidiary, SPN Resources, LLC, and compete in the Gulf of Mexico construction market for both installation and removal projects. At December 31, 2005, the total amount of progress payments made on the crane was approximately $6.7 million. We also placed a deposit of approximately $0.6 million on an anchor handling tug for the barge. The remaining balance of approximately $5.3 million is expected to be paid in the first quarter of 2006.

We also paid additional consideration for prior acquisitions of $5.3 million in 2005, all of which were capitalized and accrued during 2004.

We have a bank credit facility consisting of a revolving credit facility of $150 million, with an option to increase it to $250 million. Any balance outstanding on the revolving credit facility is due on October 31, 2008. The credit facility bears interest at a LIBOR rate plus margins that depend on the Company’s leverage ratio. As of February 17, 2006, there was no balance outstanding on this credit facility. Indebtedness under the credit facility is secured by substantially all of the Company’s assets, including the pledge of the stock of the Company’s principal subsidiaries. The credit facility contains customary events of default and requires that the Company satisfy various financial covenants. It also limits the Company’s capital expenditures, its ability to pay dividends or make other distributions, make acquisitions, make changes to the Company’s capital structure, create liens, incur additional indebtedness or assume additional decommissioning liabilities which would require supplemental bonding.

We have $17.4 million outstanding at December 31, 2005 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 also have outstanding $200 million of 8 7/8% senior notes due 2011. The indenture governing the senior notes requires semi-annual interest payments on every May 15^th and November 15^th through the maturity date of May 15, 2011. We may redeem the senior notes during the 12-month period commencing May 15, 2006 at 104.438% of the principal amount redeemed. The indenture governing the senior notes contains certain covenants that, among other things, prevent us from incurring additional debt, paying dividends or making other distributions, unless our ratio of cash flow to interest expense is at least 2.25 to 1, except that we may incur debt in addition to the senior notes in an amount equal to 30% of our net tangible assets, which was approximately $208 million at December 31, 2005. The indenture also contains covenants that restrict our ability to create certain liens, sell assets or enter into certain mergers or acquisitions.

The following table summarizes our contractual cash obligations and commercial commitments at December 31, 2005 (amounts in thousands) for our long-term debt (including estimated interest payments), decommissioning liabilities, operating leases and contractual obligations. The decommissioning liability amounts do not give any effect to our contractual right to receive amounts from third parties, which is approximately $31.5 million, when decommissioning operations are performed. We do not have any other material obligations or commitments.


Description	2006		2007		2008		2009		2010		Thereafter

Long-term debt, including estimated interest payments	$	19,670	$	19,617	$	19,565	$	19,513	$	19,461	$	229,549
Decommissioning liabilities		14,268		26,408		7,294		3,831		13,609		56,499
Operating leases		6,360		4,837		2,723		1,667		1,137		14,181
Derrick barge and tug construction		21,263		—		—		—		—		—

Total	$	61,561	$	50,862	$	29,582	$	25,011	$	34,207	$	300,229

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, 2005, the maximum additional consideration payable for our prior acquisitions was approximately $2.4 million. These amounts are not classified as liabilities under generally accepted accounting principles and are not reflected in our financial statements until the amounts are fixed and determinable. When amounts are determined, they are capitalized as part of the purchase price of the related acquisition. We do not have any other financing arrangements that are not required under generally accepted accounting principles to be reflected in our financial statements.

We have identified capital expenditure projects that will require approximately $214 million in 2006, exclusive of any acquisitions for, among other things, geographic expansion, the construction of our derrick barge and anchor handling tug, the refurbishment of a 200-foot class liftboat and reserve additions in our oil and gas segment. We believe that our current working capital, cash generated from our operations and availability under our revolving credit facility will provide sufficient funds for our identified capital projects.

We intend to continue implementing our growth strategy of increasing our scope of services through both internal growth and strategic acquisitions. We expect to continue to make the capital expenditures required to implement our growth strategy in amounts consistent with the amount of cash generated from operating activities, the availability of additional financing and our credit facility. Depending on the size of any future acquisitions, we may

require additional equity or debt financing in excess of our current working capital and amounts available under our revolving credit facility.

Hedging Activities

We enter into hedging transactions with major financial institutions to secure a commodity price for a portion of our future production and to reduce our exposure to fluctuations in the price of oil. We do not enter into hedging transactions for trading purposes. Crude oil hedges are settled based on the average of the reported settlement prices for West Texas Intermediate crude on the New York Mercantile Exchange (NYMEX) for each month. We had no natural gas hedges as of December 31, 2005 and 2004. We use financially-settled crude oil swaps and zero-cost collars that provide floor and ceiling prices with varying upside price participation. Our swaps and zero-cost collars are designated and accounted for as cash flow hedges.

With a financially-settled swap, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the hedged price for the transaction, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. With a zero-cost collar, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price of the collar, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar. We recognize the fair value of all derivative instruments as assets or liabilities on the balance sheet. Changes in the fair value of cash flow hedges are recognized, to the extent the hedge is effective, in other comprehensive income until the hedged item is recognized in oil and gas revenues. For the year ended December 31, 2005, hedging settlement payments reduced oil revenues by approximately $10.2 million dollars and gains or losses due to hedge ineffectiveness were not material.

We had the following hedging contracts as of December 31, 2005:

Crude Oil Positions

Instrument

Strike

Volume (Bbls)

Remaining Contract Term

Type

Price (Bbl)

Daily

Total (Bbls)

01/06 - 8/06

Swap

39.45

1,000 - 1,013

274,388

01/06 - 8/06

Collar

35.00/$45.60

1,000 - 1,013

274,388

Recently Issued Accounting Pronouncements

In December 2004, the Financial Accounting Standards Board revised its Statement of Financial Accounting Standards No. 123 (FAS No. 123R), “Accounting for Stock Based Compensation.” Under FAS No. 123R, companies will be required to recognize as expense the estimated fair value of all share-based payments to employees, including the fair value of employee stock options. This expense will be recognized over the period during which the employee is required to provide service in exchange for the award. Pro forma disclosure of the estimated expense impact of such awards is no longer an alternative to expense recognition in the financial statements. FAS No. 123R is effective for public companies in the first annual period beginning after June 15, 2005, and accordingly, we will adopt the provisions of FAS No. 123R effective January 1, 2006. We anticipate using the modified prospective application transition method, which does not include restatement of prior periods. We expect to record approximately $89,000 of compensation expense in 2006 due to the adoption of FAS No. 123R for share-based awards granted prior to January 1, 2006. We expect the effect of the adoption on future share-based awards to be consistent with the disclosure of pro forma net income and earnings per share as displayed in note 1 of our consolidated financial statements included in Item 8 of this Form 10-K.

In May 2005, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 154 (FAS No. 154), “Accounting Changes and Error Corrections.” This Statement replaces APB Opinion No. 20, “Accounting Changes” and FASB Statement No. 3, “Reporting Accounting Changes in Interim Financial Statements.” FAS No. 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes, unless impracticable, retrospective application as the required method for reporting all changes in accounting principle in the absence of explicit transition requirements of new pronouncements. FAS No.

154 is effective for accounting changes and error corrections made in fiscal years beginning after December 15, 2005.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

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

Foreign Currency Exchange Rates

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

We do not hold any foreign currency exchange forward contracts and/or currency options. We have 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 foreign subsidiaries are translated at current exchange rates, while income and expense are translated at average rates for the period. Translation gains and losses are reported as the foreign currency translation component of accumulated other comprehensive income in stockholders’ equity.

Interest Rates

At December 31, 2005, none of our long-term debt outstanding had variable interest rates, and we had no interest rate risks at that time.

Commodity Price Risk

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

We use derivative commodity instruments to manage commodity price risks associated with future oil and natural gas production. As of December 31, 2005, we had the following contracts in place:

Crude Oil Positions

Instrument

Strike

Volume (Bbls)

Remaining Contract Term

Type

Price (Bbl)

Daily

Total (Bbls)

01/06 - 8/06

Swap

39.45

1,000 - 1,013

274,388

01/06 - 8/06

Collar

35.00/$45.60

1,000 - 1,013

274,388

Our hedged volume as of December 31, 2005 was approximately 50% of our estimated production from proved reserves for the balance of the terms of the contracts. Had these contracts been terminated at December 31, 2005, the estimated loss would have been $6.9 million, net of taxes.

We used a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of crude oil would have on the fair value of its existing derivative instruments. Based on the derivative instruments outstanding at December 31, 2005, a 10% increase in the underlying commodity price, increased the net estimated loss associated with the commodity derivative instrument by $1.9 million.

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, 2005. 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, 2005 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, 2005.

Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which appears herein.


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

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, 2005 and 2004, 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, 2005. In connection with our audit of the consolidated financial statements, we also have audited the accompanying financial statement schedule, “Valuation and Qualifying Accounts,” for the years ended December 31, 2005, 2004 and 2003. 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, 2005 and 2004, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therin.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Superior Energy Services, Inc.’s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 8, 2006 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

KPMG LLP

New Orleans, Louisiana
March 8, 2006

Report of Independent Registered Public Accounting Firm

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

We have audited management’s assessment, included in the accompanying “Management’s Report on Internal Control over Financial Reporting,” that Superior Energy Services, Inc. maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Superior Energy Services, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

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

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

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

In our opinion, management’s assessment that Superior Energy Services, Inc. maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, Superior Energy Services, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, 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. AND SUBSIDIARIES
Consolidated Balance Sheets
December 31, 2005 and 2004
(in thousands, except share data)


	2005			2004
ASSETS

Current assets:
Cash and cash equivalents	$	54,457		$	15,281
Accounts receivable, net of allowance for doubtful accounts of $11,569 and $8,364 at December 31, 2005 and 2004, respectively		196,365			156,235
Income taxes receivable		—			2,694
Current portion of notes receivable		2,364			9,611
Prepaid insurance and other		51,116			28,203

Total current assets		304,302			212,024

Property, plant and equipment, net		440,328			431,334
Oil and gas assets, net, under the successful efforts method of accounting		94,634			83,817
Goodwill, net		220,064			226,593
Notes receivable		29,483			29,131
Investments in affiliates		—			13,552
Other assets, net		8,439			7,462

Total assets	$	1,097,250		$	1,003,913


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	42,035		$	36,496
Accrued expenses		69,926			56,796
Income taxes payable		11,353			—
Fair value of commodity derivative instruments		10,792			2,018
Current portion of decommissioning liabilities		14,268			23,588
Current maturities of long-term debt		810			11,810

Total current liabilities		149,184			130,708


Deferred income taxes		97,987			103,372
Decommissioning liabilities		107,641			90,430
Long-term debt		216,596			244,906
Other long-term liabilities		1,468			618

Stockholders’ equity:
Preferred stock of $0.01 par value. Authorized, 5,000,000 shares; none issued		—			—
Common stock of $0.001 par value. Authorized, 125,000,000 shares; issued and outstanding 79,499,927 and 76,766,303 shares at December 31, 2005 and 2004, respectively		79			77
Additional paid in capital		428,507			398,073
Accumulated other comprehensive income (loss)		(4,916	)		2,884
Retained earnings		100,704			32,845

Total stockholders’ equity		524,374			433,879

Total liabilities and stockholders’ equity	$	1,097,250		$	1,003,913

See accompanying notes to consolidated financial statements.

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Operations
Years Ended December 31, 2005, 2004 and 2003
(in thousands, except per share data)


	2005			2004			2003
Oilfield service and rental revenues	$	656,423		$	527,331		$	499,884
Oil and gas revenues		78,911			37,008			741

Total revenues		735,334			564,339			500,625

Cost of oilfield services and rentals		330,200			288,561			289,276
Cost of oil and gas sales		45,804			21,547			331

Total cost of services, rentals and sales		376,004			310,108			289,607

Depreciation, depletion, amortization and accretion		89,288			67,337			48,853
General and administrative expenses		140,989			110,605			94,822
Reduction in value of assets		6,994			—			—
Gain on sale of liftboats		3,544			—			—

Income from operations		125,603			76,289			67,343

Other income (expense):
Interest expense, net of amounts capitalized		(21,862	)		(22,476	)		(22,477	)
Interest income		2,201			1,766			209
Other income		—			—			2,762
Equity in earnings of affiliates		1,339			1,329			985
Reduction in value of investment in affiliate		(1,250	)		—			—


Income before income taxes		106,031			56,908			48,822

Income taxes		38,172			21,056			18,308


Net income	$	67,859		$	35,852		$	30,514


Basic earnings per share	$	0.87		$	0.48		$	0.41


Diluted earnings per share	$	0.85		$	0.47		$	0.41


Weighted average common shares used in computing earnings per share:
Basic		78,321			74,896			73,970
Incremental common shares from stock options		1,414			1,004			678

Diluted		79,735			75,900			74,648

See accompanying notes to consolidated financial statements.

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Changes in Stockholders’ Equity
Years Ended December 31, 2005, 2004 and 2003
(in thousands, except share data)


														Accumulated			Retained
	Preferred				Common						Additional			other			earnings
	stock		Preferred		stock			Common			paid-in			comprehensive			(Accumulated
	shares		stock		shares			stock			capital			income (loss)			deficit)			Total

Balances, December 31, 2002		—	$	—		73,819,341		$	74		$	368,746		$	43		$	(33,521	)	$	335,342

Comprehensive income:
Net income		—		—		—			—			—			—			30,514			30,514
Other comprehensive income - Foreign currency translation adjustment		—		—		—			—			—			221			—			221


Total comprehensive income		—		—		—			—			—			221			30,514			30,735
Exercise of stock options and directors’ stock compensation		—		—		279,740			—			1,710			—			—			1,710
Tax benefit from stock options		—		—		—			—			342			—			—			342


Balances, December 31, 2003		—		—		74,099,081			74			370,798			264			(3,007	)		368,129

Comprehensive income:
Net income		—		—		—			—			—			—			35,852			35,852
Other comprehensive income - Changes in fair value of outstanding hedging positions, net of tax		—		—		—			—			—			(1,661	)		—			(1,661	)
Foreign currency translation adjustment		—		—		—			—			—			4,281			—			4,281


Total comprehensive income		—		—		—			—			—			2,620			35,852			38,472
Stock issued for cash		—		—		11,151,121			12			130,253			—			—			130,265
Purchase and retirement of stock		—		—		(9,696,627	)		(10	)		(113,428	)		—			—			(113,438	)
Grant of restricted stock units		—		—		—			—			180			—			—			180
Conversion of restricted stock units		—		—		9,783			—			—			—			—			—
Exercise of stock options and directors’ stock compensation		—		—		1,202,945			1			8,295			—			—			8,296
Tax benefit from stock options		—		—		—			—			1,975			—			—			1,975


Balances, December 31, 2004		—		—		76,766,303			77			398,073			2,884			32,845			433,879

Comprehensive income:
Net income		—		—		—			—			—			—			67,859			67,859
Other comprehensive income - Changes in fair value of outstanding hedging positions, net of tax		—		—		—			—			—			(2,662	)		—			(2,662	)
Foreign currency translation adjustment		—		—		—			—			—			(5,138	)		—			(5,138	)


Total comprehensive income		—		—		—			—			—			(7,800	)		67,859			60,059
Grant of restricted stock units		—		—		—			—			158			—			—			158
Grant of restricted stock		—		—		24,000			—			178			—			—			178
Exercise of stock options		—		—		2,709,624			2			18,157			—			—			18,159
Tax benefit from stock options		—		—		—			—			11,941			—			—			11,941


Balances, December 31, 2005		—	$	—		79,499,927		$	79		$	428,507		$	(4,916	)	$	100,704		$	524,374

See accompanying notes to consolidated financial statements.

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Years Ended December 31, 2005, 2004 and 2003
(in thousands)


	2005			2004			2003
Cash flows from operating activities:
Net income	$	67,859		$	35,852		$	30,514
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		89,288			67,337			48,853
Deferred income taxes		442			15,234			15,183
Reduction in value of assets		6,994			—			—
Equity in income of affiliates		(1,339	)		(1,329	)		(985	)
Reduction in value of investment in affiliate		1,250			—			—
Gain on sale of liftboats		(3,544	)		—			—
Other income		—			—			(2,762	)
Amortization of debt acquisition costs		1,127			887			1,026
Changes in operating assets and liabilities, net of acquisitions:
Receivables		(32,095	)		(35,279	)		104
Other, net		(11,263	)		(9,346	)		1,773
Accounts payable		5,696			16,142			(1,932	)
Accrued expenses		16,599			13,866			2,561
Decommissioning liabilities		(8,772	)		(9,157	)		—
Income taxes		26,137			(2,876	)		5,905

Net cash provided by operating activities		158,379			91,331			100,240


Cash flows from investing activities:
Payments for capital expenditures		(125,166	)		(74,125	)		(50,175	)
Acquisitions of businesses, net of cash acquired		(6,435	)		(24,361	)		(14,298	)
Acquisitions of oil and gas properties, net of cash acquired		3,686			(10,676	)		—
Cash proceeds from sale of liftboats		19,588			—			—
Cash proceeds from sale of affiliate		12,489			—			—
Cash proceeds from insurance settlement		—			—			8,000
Other		(1,097	)		—			313


Net cash used in investing activities		(96,935	)		(109,162	)		(56,160	)


Cash flows from financing activities:
Net payments on revolving credit facility		—			—			(9,250	)
Principal payments on long-term debt		(39,310	)		(13,713	)		(43,089	)
Proceeds from long-term debt		—			—			23,000
Payment of debt acquisition costs		(439	)		(60	)		(479	)
Proceeds from exercise of stock options		18,161			10,271			2,052
Proceeds from issuance of stock		—			130,265			—
Purchase and retirement of stock		—			(113,438	)		—


Net cash provided by (used in) financing activities		(21,588	)		13,325			(27,766	)


Effect of exchange rate changes in cash		(680	)		(7	)		—


Net increase (decrease) in cash and cash equivalents		39,176			(4,513	)		16,314

Cash and cash equivalents at beginning of year		15,281			19,794			3,480


Cash and cash equivalents at end of year	$	54,457		$	15,281		$	19,794

See accompanying notes to consolidated financial statements.

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
December 31, 2005, 2004 and 2003

(1) Summary of Significant Accounting Policies

	(a)		Basis of Presentation

			The consolidated financial statements include the accounts of Superior Energy Services, Inc. and subsidiaries (the Company). All significant intercompany accounts and transactions are eliminated in consolidation. Certain previously reported amounts have been reclassified to conform to the 2005 presentation.

	(b)		Business

			The Company is a leading provider of specialized oilfield services and equipment focusing on serving the production-related needs of oil and gas companies in the Gulf of Mexico and the drilling-related needs of oil and gas companies throughout the world. The Company provides most of the services, tools and liftboats necessary to maintain, enhance and extend offshore producing wells, as well as plug and abandonment services at the end of their life cycle.

			In December 2003, the Company began acquiring oil and gas properties in order to provide additional opportunities for its well intervention and platform management operations in the Gulf of Mexico. The Company intends to continue to acquire mature properties from its customers with modest amounts of estimated remaining productive life, to provide all of its services to the properties to produce any remaining proven oil and gas reserves and to decommission and abandon the properties.

	(c)		Use of Estimates

			The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

	(d)		Major Customers and Concentration of Credit Risk

			A majority of the Company’s business is conducted with major and independent oil and gas exploration companies. The Company continually evaluates the financial strength of its customers and provides allowances for probable credit losses when deemed necessary but does not require collateral to support the customer receivables.

			The market for the Company’s services and products is primarily the offshore oil and gas industry in the Gulf of Mexico. Oil and gas companies make capital expenditures on exploration, drilling and production operations offshore. The level of these expenditures has been characterized by significant volatility.

			The Company derives a significant amount of revenue from a small number of major and independent oil and gas companies. In 2005, Shell accounted for approximately 10% of total revenue, primarily related to our oil and gas and rental segments. No customer accounted for more than 10% of the Company’s total revenue in 2004. In 2003, one customer accounted for approximately 11% of its total revenue, primarily in the well intervention and other oilfield services segments. The Company’s inability to continue to perform services for a number of large existing customers, if not offset by sales to new or

			existing customers, could have a material adverse effect on the Company’s business and financial condition.

	(e)		Cash Equivalents

			The Company considers all short-term deposits with a maturity of ninety days or less to be cash equivalents.

	(f)		Accounts Receivable and Allowances

			Trade accounts receivables are recorded at the invoiced amount and do not bear interest. The Company maintains allowances for bad debts and various other adjustments. The allowance for doubtful accounts is based on the Company’s best estimate of the amount of probable uncollectible amounts in existing accounts receivable. The Company determines the allowances based on historical write-off experience and specific identification.

	(g)		Prepaid Insurance and Other

			Prepaid insurance and other includes approximately $23.9 million and $11.1 million in insurance receivables at December 31, 2005 and 2004, respectively. The December 31, 2005 balance is primarily due to the impact of Hurricanes Katrina and Rita on our oil and gas properties, as well as our buildings and equipment. The December 31, 2004 balance is primarily related to the impact of Hurricane Ivan on our oil and gas properties. The insurance deductibles on Hurricanes Katrina and Rita of approximately $1 million were expensed during 2005. All amounts not expected to be reimbursed by insurance are expensed as incurred.

	(h)		Property, Plant and Equipment

			Property, plant and equipment are stated at cost. With the exception of the Company’s liftboats and oil and gas assets, depreciation is computed using the straight-line method over the estimated useful lives of the related assets as follows:


Buildings and improvements			5 to 40 years
Marine vessels and equipment			5 to 25 years
Machinery and equipment			5 to 20 years
Automobiles, trucks, tractors and trailers			2 to 10 years
Furniture and fixtures			3 to 10 years

			Marine vessels and oil and gas producing assets are depreciated or depleted based on utilization or units-of-production, because depreciation and depletion occur primarily through use rather than through the passage of time. Units of production depreciation on marine vessels is subject to a minimum amount of depreciation each year.

			The Company capitalizes interest on borrowings used to finance the cost of major capital projects during the active construction period. Capitalized interest is added to the cost of the underlying assets and is amortized over the useful lives of the assets. For 2005 and 2003, the Company capitalized approximately $456,000 and $87,000, respectively, of interest for various capital projects. There was no interest capitalized during 2004.

			Long-lived assets and certain identifiable intangibles are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the assets. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value. Assets are grouped by subsidiary or division for the impairment testing,

			except for liftboats which are grouped together by similar leg-lengths. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell.

			The Company’s subsidiary, SPN Resources, LLC, acquires oil and natural gas properties and assumes the related decommissioning liabilities. The Company follows the successful efforts method of accounting for its investment in oil and natural gas properties. Under the successful efforts method, the costs of successful exploratory wells and leases containing productive reserves are capitalized. Costs incurred to drill and equip developmental wells, including unsuccessful development wells are capitalized. Other costs such as geological and geophysical costs and the drilling costs of unsuccessful exploratory wells are expensed. SPN Resources’ property purchases are recorded at the value exchanged at closing, combined with an estimate of its proportionate share of the decommissioning liability assumed in the purchase. All capitalized costs are accumulated and recorded separately for each field and allocated to leasehold costs and well costs. Leasehold costs are depleted on a units-of-production basis based on the estimated remaining equivalent proved oil and gas reserves of each field. Well costs are depleted on a units-of-production basis based on the estimated remaining equivalent proved developed oil and gas reserves of each field.

			The Company adopted Financial Accounting Standards Board Staff Position FAS 19-1, “Accounting for Suspended Well Costs” (FSP 19-1) effective July 1, 2005. FSP 19-1 amended Statement of Financial Accounting Standards No. 19 “Financial Accounting and Reporting by Oil and Gas Producing Companies” (Statement 19), to permit the continued capitalization of exploratory well costs beyond one year if (a) the well found a sufficient quantity of reserves to justify its completion as a producing well and (b) the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project. The Company has not, and does not currently drill in the areas that require major capital expenditures before production can begin. The Company evaluated all existing capitalized well costs under the provisions of FSP-19-1 and determined there was no impact to the Company’s consolidated financial statements.

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

	(i)		Goodwill

			The Company accounts for goodwill and other intangible assets in accordance with Statement of Financial Accounting Standards No. 142 (FAS No. 142), “Goodwill and Other Intangible Assets.” FAS No. 142 requires that goodwill as well as other intangible assets with indefinite lives no longer be amortized, but instead tested annually for impairment. To test for impairment, the Company identifies its reporting units (which are consistent with the Company’s reportable segments) and determines the carrying value of each reporting unit by assigning the assets and liabilities, including goodwill and intangible assets, to the reporting units. The Company then estimates the fair value of each reporting unit and compares it to the reporting unit’s carrying value. Based on this test, the fair value of the reporting units exceeded the carrying amount, and the second step of the impairment test is not required. No impairment loss was recognized in the years ended December 31, 2005, 2004 or 2003 under this method. However, the Company reduced the value of goodwill by approximately $3.8 million to approximate the sales price of its subsidiary, Environmental Treatment Team, L.L.C., (ETT), which was sold in the first quarter of 2006 (see note 3). Goodwill also decreased by approximately $2.7 million in 2005 as the result of changes in foreign currency exchange rates. Accumulated amortization of goodwill is $9.2 million at December 31, 2005 and 2004.

	(j)		Notes Receivable

			Notes receivable consist primarily of commitments from the sellers of oil and gas properties towards the abandonment of the acquired properties. Pursuant to the agreement between the Company and a seller,

			the Company will invoice the seller agreed upon amounts during the course of decommissioning (abandonment and structure removal). These receivables are recorded at present value, and the related discounts are amortized to interest income, based on the expected timing of the decommissionings.

	(k)		Other Assets

			Other assets consist primarily of debt acquisition costs and deferred compensation plan assets. Debt acquisition costs are being amortized over the term of the related debt, which is from three to twenty-five years. The amortization of debt acquisition costs, which is classified as interest expense, was approximately $1,127,000, $887,000 and $1,026,000 for the years ended December 31, 2005, 2004 and 2003, respectively. Accumulated amortization of other assets is approximately $6,062,000 and $4,604,000 at December 31, 2005 and 2004, respectively.

	(l)		Decommissioning Liability

			The Company records estimated future decommissioning liabilities related to its oil and gas producing properties pursuant to the provisions of Statement of Financial Accounting Standards No. 143 (FAS No. 143), “Accounting for Asset Retirement Obligations.” FAS No. 143 requires entities to record the fair value of a liability at estimated present value for an asset retirement obligation (decommissioning liabilities) in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. Subsequent to initial measurement, the decommissioning liability is required to be accreted each period to present value. The Company’s decommissioning liabilities consist of costs related to the plugging of wells, the removal of facilities and equipment and site restoration on oil and gas properties.

			The Company estimates the cost that would be incurred if it contracted an unaffiliated third party to plug and abandon wells, abandon the pipelines, decommission and remove the platforms and pipelines and clear the sites of its oil and gas properties, and uses that estimate to record its proportionate share of the decommissioning liability. In estimating the decommissioning liability, the Company performs detailed estimating procedures, analysis and engineering studies. Whenever practical, the Company utilizes its own equipment and labor services to perform well abandonment and decommissioning work. When the Company performs these services, all recorded intercompany revenues are eliminated in the consolidated financial statements. The recorded decommissioning liability associated with a specific property is fully extinguished when the property is abandoned. The recorded liability is first reduced by all cash expenses incurred to abandon and decommission the property. If the recorded liability exceeds (or is less than) the Company’s out-of-pocket costs, then the difference is reported as income (or loss) within revenue during the period in which the work is performed. The Company reviews the adequacy of its decommissioning liability whenever indicators suggest that the estimated cash flows needed to satisfy the liability have changed materially. The timing and amounts of these cash flows are estimates, and changes to these estimates may result in additional (or decreased) liabilities recorded, which in turn would increase (or decrease) the carrying values of the related oil and gas properties.

			SPN Resources purchased its first oil and gas properties and assumed the related decommissioning liabilities in December 2003, thus comparable data for the year ended December 31, 2003 is not material. The following table summarizes the activity for the Company’s decommissioning liability for the twelve months ended December 31, 2005 and 2004 (amounts in thousands):


	Year Ended December 31,
	2005			2004
Decommissioning liabilities, at beginning of period	$	114,018		$	38,853
Liabilities acquired and incurred		11,494			83,021
Liabilities settled		(8,772	)		(9,157	)
Accretion		4,476			2,836
Revision in estimated liabilities		693			(1,535	)

Total		121,909			114,018
Current portion of decommissioning liabilities		14,268			23,588

Decommissioning liabilities, at end of period	$	107,641		$	90,430

	(m)		Revenue Recognition

			Revenue is recognized when services or equipment are provided. The Company contracts for marine, well intervention and environmental projects either on a day rate or turnkey basis, with a majority of its projects conducted on a day rate basis. The Company’s rental tools are rented on a day rate basis, and revenue from the sale of equipment is recognized when the equipment is shipped. Reimbursements from customers for the cost of rental tools that are damaged or lost down-hole are reflected as revenue at the time of the incident. The Company recognizes oil and gas revenue from its interests in producing wells as oil and natural gas is produced and sold from those wells.

	(n)		Income Taxes

			The Company provides for income taxes in accordance with Statement of Financial Accounting Standards No. 109 (FAS No. 109), “Accounting for Income Taxes.” FAS No. 109 requires an asset and liability approach for financial accounting and reporting for income taxes. Deferred income taxes reflect the impact of temporary differences between amounts of assets and liabilities for financial reporting purposes and such amounts as measured by tax laws.

	(o)		Earnings per Share

			Basic earnings per share is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share is computed in the same manner as basic earnings per share except that the denominator is increased to include the number of additional common shares that could have been outstanding assuming the exercise of stock options and restricted stock units and the potential shares that would have a dilutive effect on earnings per share.

	(p)		Financial Instruments

			The fair value of the Company’s financial instruments of cash, accounts receivable and current maturities of long-term debt approximates their carrying amounts. The fair value of the Company’s long-term debt is approximately $227 million at December 31, 2005.

	(q)		Foreign Currency Translation

			Assets and liabilities of the Company’s foreign subsidiaries are translated at current exchange rates, while income and expenses are translated at average rates for the period. Translation gains and losses are reported as the foreign currency translation component of accumulated other comprehensive income in stockholders’ equity.

	(r)		Stock Based Compensation

			The Company accounts for its stock based compensation under the principles prescribed by the Accounting Principles Board’s Opinion No. 25 (Opinion No. 25), “Accounting for Stock Issued to Employees” However, Statement of Financial Accounting Standards No. 123 (FAS No. 123), “Accounting for Stock-Based Compensation” permits the continued use of the intrinsic-value based method prescribed by Opinion No. 25 but requires additional disclosures, including pro forma calculations of earnings and net earnings per share as if the fair value method of accounting prescribed by FAS No. 123 had been applied. No stock based compensation costs from stock options are reflected in net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. Stock compensation costs from the grant of restricted stock units and restricted stock are expensed as incurred (see note 11). The pro forma data presented below is not representative of the effects on reported amounts for future years (amounts are in thousands, except per share amounts).


	2005			2004			2003
Net income, as reported	$	67,859		$	35,852		$	30,514
Stock-based employee compensation expense, net of tax		(4,421	)		(6,999	)		(2,671	)


Pro forma net income	$	63,438		$	28,853		$	27,843


Basic earnings per share:
Earnings, as reported	$	0.87		$	0.48		$	0.41
Stock-based employee compensation expense, net of tax		(0.06	)		(0.09	)		(0.04	)


Pro forma earnings per share	$	0.81		$	0.39		$	0.37


Diluted earnings per share:
Earnings, as reported	$	0.85		$	0.47		$	0.41
Stock-based employee compensation expense, net of tax		(0.06	)		(0.09	)		(0.04	)


Pro forma earnings per share	$	0.79		$	0.38		$	0.37


Black-Scholes option pricing model assumptions:
Risk free interest rate		3.85	%		4.28	%		2.65	%
Expected life (years)		6			5			3
Volatility		38.91	%		65.22	%		58.61	%
Dividend yield		—			—			—

In December 2004, the Financial Accounting Standards Board revised its Statement of Financial Accounting Standards No. 123 (FAS No. 123R), “Accounting for Stock Based Compensation.” Under FAS No. 123R, companies will be required to recognize as expense the estimated fair value of all share-based payments to employees, including the fair value of employee stock options. This expense will be recognized over the period during which the employee is required to provide service in exchange for the award. Pro forma disclosure of the estimated expense impact of such awards is no longer an alternative to expense recognition in the financial statements. FAS No. 123R is effective for public companies in the first annual period beginning after June 15, 2005, and accordingly, the Company will adopt the provisions of FAS No. 123R effective January 1, 2006. The Company anticipates using the modified prospective application transition method, which does not include restatement of prior periods. The Company expects to record approximately $89,000 of compensation expense in 2006 due to the adoption of FAS No. 123R for share-based awards granted prior to January 1, 2006. The Company expects the

			effect of the adoption on future awards to be consistent with the disclosure of pro forma net income and earnings per share as displayed above.

			Long-Term Incentive Plan

			In May 2005, the Company’s stockholders approved the 2005 Stock Incentive Plan (“2005 Incentive Plan”) to provide long-term incentives to its officers, key employees, consultants and advisers (“Eligible Participants”). Under the 2005 Incentive Plan, the Company may grant incentive stock options, non-qualified stock options, restricted stock, restricted stock units, stock appreciation rights, other stock-based awards or any combination thereof to Eligible Participants for up to 4,000,000 shares of common stock. The Compensation Committee of the Board of Directors establishes the term and the exercise price of any stock options granted under the 2005 Incentive Plan, provided the exercise price may not be less than the fair market value of the common stock on the date of grant. On June 24, 2005, the Compensation Committee awarded approximately 864,000 non-qualified stock options to Eligible Participants under the 2005 Incentive Plan. This grant was fully-vested by December 31, 2005.

			On June 24, 2005, the Compensation Committee also awarded approximately 32,000 performance share units (“Units”). The performance period for the Units runs from January 1, 2005 through December 31, 2007. The two performance measures applicable to all participants are the Company’s return on invested capital and total shareholder return relative to those of the Company’s pre-defined “peer group.” Participants can earn from $0 to $200 per Unit, as determined by the Company’s achievement of the performance measures. The Units provide for settlement in cash or up to 50% in equivalent value in Company common stock, if the participant has met specified continued service requirements. The Company’s compensation expense related to the grant of the Units was approximately $1.1 million, which is reflected in general and administrative expenses, for the year ended December 31, 2005.

			Subsequent event

			On February 23, 2006, the Compensation Committee granted long-term incentive awards to each of the Company’s named executive officers and other key employees of the Company under its stockholder approved 2005 Stock Incentive Plan. These awards consisted of approximately 213,000 non-qualified stock options, 104,000 shares of restricted stock and 34,000 performance share units (“Units”).

			The non-qualified options will be exercisable in equal installments on the anniversary of the date of the grant for three consecutive years, and will expire on the tenth anniversary of the date grant. Holders of the shares of restricted stock are entitled to all rights of a shareholder of the Company with respect to the restricted stock, including the right to vote the shares and receive all dividends and other distributions declared thereon. The shares of restricted stock will be exercisable in equal installments on the anniversary date of the grant for three consecutive years. The performance period for the Units runs from January 1, 2006 through December 31, 2008. The two performance measures applicable to all participants are the Company’s return on invested capital and total shareholder return relative to those of the Company’s pre-defined “peer group.” Participants can earn from $0 to $200 per Unit, as determined by the Company’s achievement of the performance measures. The Units provide for settlement in cash or up to 50% in equivalent value in Company common stock, if the participant has met specified continued service requirements.

	(s)		Hedging Activities

			The Company enters into hedging transactions with major financial institutions to secure a commodity price for a portion of future production and to reduce the Company’s exposure to fluctuations in the price of oil. The Company does not enter into hedging transactions for trading purposes. Crude oil hedges are settled based on the average of the reported settlement prices for West Texas Intermediate crude on the New York Mercantile Exchange (NYMEX) for each month. The Company had no natural gas hedges as of December 31, 2005 and 2004. The Company uses financially-settled crude oil swaps and zero-cost collars that provide floor and ceiling prices. The Company’s swaps and zero-cost collars are designated and accounted for as cash flow hedges.

With a financially-settled swap, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the hedged price for the transaction, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. With a zero-cost collar, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price of the collar, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar. The Company recognizes the fair value of all derivative instruments as assets or liabilities on the balance sheet. Changes in the fair value of cash flow hedges are recognized, to the extent the hedge is effective, in other comprehensive income until the hedged item is settled and recorded in oil and gas revenue. For the years ended December 31, 2005 and 2004, hedging settlement payments reduced oil revenues by approximately $10.2 million and $1.6 million, respectively. The Company recorded no gains or losses due to hedge ineffectiveness, but any gains or losses resulting from hedge ineffectiveness would be recorded in revenue.

The Company had the following hedging contracts as of December 31, 2005:

Crude Oil Positions

Instrument

Strike

Volume (Bbls)

Remaining Contract Term

Type

Price (Bbl)

Daily

Total (Bbls)

01/06 — 8/06

Swap

39.45

1,000 — 1,013

274,388

01/06 — 8/06

Collar

35.00/$45.60

1,000 — 1,013

274,388

Based upon current market prices, the Company expects to transfer approximately $6.9 million of net deferred losses in accumulated other comprehensive loss as of December 31, 2005 to earnings during the next twelve months when the forecasted transactions actually occur.

(t)		Other Comprehensive Income

		The following table reconciles the change in accumulated other comprehensive income for the years ended December 31, 2005 and 2004 (amounts in thousands):


	Year Ended December 31,
	2005			2004
Accumulated other comprehensive income, December 31, 2004 and 2003, respectively	$	2,884		$	264

Other comprehensive income (loss), net of tax:
Hedging activities:
Reclassification adjustment for settled contracts, net of tax of $3,656 in 2005 and $576 in 2004		6,499			981
Changes in fair value of outstanding hedging positions, net of tax of ($6,545) in 2005 and ($1,552) in 2004		(11,637	)		(2,642	)
Foreign currency translation adjustment		(2,662	)		4,281


Total other comprehensive income		(7,800	)		2,620


Accumulated other comprehensive income, December 31, 2005 and 2004, respectively	$	(4,916	)	$	2,884

(2)

Supplemental Cash Flow Information

The following table includes the Company’s supplemental cash flow information for the years ended December 31, 2005, 2004 and 2003 (amounts in thousands):


	2005			2004			2003
Cash paid for interest	$	21,152		$	23,320		$	23,633


Cash paid (received) for income taxes	$	10,789		$	7,360		$	(4,125	)


Details of business acquisitions:
Fair value of assets	$	6,627		$	25,614		$	51,103
Fair value of liabilities		(31	)		(1,158	)		(35,270	)

Cash paid		6,596			24,456			15,833
Less cash acquired		(163	)		(95	)		(1,535	)

Net cash paid for acquisitions	$	6,433		$	24,361		$	14,298


Details of oil and gas property acquisitions:
Fair value of assets	$	11,494		$	97,792		$	39,509
Fair value of liabilities		(11,494	)		(82,107	)		(39,509	)

Cash paid		—			15,685			—
Less cash acquired		(3,686	)		(5,009	)		—

Net cash paid for acquisitions	$	(3,686	)	$	10,676		$	—


Non-cash investing activity:
Receivable from sale of affiliate	$	1,305		$	—		$	—


Additional consideration payable on acquisitions	$	—		$	5,272		$	11,263


Note receivable from asset disposition	$	—		$	—		$	938

(3)

Reduction in Value of Assets

During the year ended December 31, 2005, the Company reduced the value of two of its mature oil and gas properties by approximately $2.1 million due to well issues affecting production rates and operating costs. The Company deemed it to be uneconomical to perform additional production enhancement work to maintain production at these properties.

Also during the year ended December 31, 2005, the Company’s oil spill containment boom manufacturing facility suffered damage from Hurricane Katrina and experienced difficulty in resuming normal business operations. As a result, the Company elected not to reopen this manufacturing facility and sell the remaining oil spill containment boom inventory. The value of the assets of this business (which consist primarily of inventory and property and equipment) were reduced by approximately $1.1 million to their estimated net realizable value.

In the first quarter of 2006, the Company sold its subsidiary ETT for approximately $18.7 million in cash. The Company reduced the net asset value of ETT by $3.8 million in 2005 to the approximate sales price of the subsidiary. For the years ended December 31, 2005, 2004 and 2003, revenue from ETT was approximately $27.7 million, $24.0 million and $21.7 million, respectively, and operating losses were approximately $5.1 million (inclusive of the $3.8 million loss), $2.1 million and $1.2 million, respectively.

(4) Gain on Sale of Liftboats

Effective June 1, 2005, the Company sold 17 of its rental liftboats with leg-lengths from 105 feet to 135 feet for $19.6 million in cash (net of costs to sell). This constituted all of the Company’s rental fleet of liftboats with leg-lengths of 135 feet or less. The Company recorded a gain of $3.5 million as a result of this transaction.

(5)

Other Income

As the result of a tropical storm, one of the Company’s 200-foot class liftboats sank in the Gulf of Mexico on June 30, 2003. The vessel was declared a total loss and the Company received $8 million of insurance proceeds for the vessel. As a result, the Company recorded a gain from the insurance proceeds of $2.8 million, which is included in other income in the year ended December 31, 2003.

(6)

Acquisitions and Dispositions

In July 2005, the Company acquired a business for an aggregate purchase price of approximately $1.3 million in cash consideration in order to geographically expand the snubbing services offered by its well intervention segment. Additional consideration, if any, will be based upon the average earnings before interest, income taxes, depreciation and amortization expense (EBITDA) over a three-year period, and will not exceed $0.4 million. This acquisition has been accounted for as a purchase and the acquired assets and liabilities have been valued at their estimated fair value. The purchase price preliminarily allocated to net assets was approximately $1.3 million, and no goodwill was recorded. The results of operations have been included from the acquisition date. The pro forma effect of operations of the acquisition when included as of the beginning of the periods presented was not material to the Consolidated Statements of Operations of the Company.

Also in July 2005, the Company’s subsidiary, SPN Resources, LLC, acquired additional oil and gas properties at Galveston 241/255 and High Island A-309 through the acquisition of three offshore Gulf of Mexico leases. Under the terms of the transaction, the Company acquired the properties and assumed the related decommissioning liabilities. The Company received $3.7 million in cash and will invoice the sellers at agreed upon prices as the decommissioning activities (abandonment and structure removal) are completed. The Company preliminarily recorded notes receivable of approximately $2.4 million, decommissioning liabilities of $11.5 million and oil and gas producing assets were recorded at their estimated fair value of $5.4 million. The pro forma effect of operations of the acquisition when included as of the beginning of the periods presented was not material to the Consolidated Statements of Operations of the Company.

In 2004, the Company’s wholly-owned subsidiary, SPN Resources, LLC, acquired additional oil and gas properties through the acquisition of interests in 19 offshore Gulf of Mexico leases. Under the terms of the transactions, the Company acquired the properties and assumed the decommissioning liabilities. In the aggregate, the Company paid $10.7 million cash, net of amounts received. The Company recorded decommissioning liabilities of approximately $83.0 million and notes and other receivables of approximately $12.5 million, and oil and gas producing assets were recorded at their estimated fair value of approximately $81.2 million.

In 2004, the Company acquired two businesses for an aggregate of $2.8 million in cash consideration in order to enhance the products and services offered by its rental tools segment and well intervention segment. These acquisitions were accounted for as purchases. The estimated fair value of the net assets acquired was approximately $1.0 million in the aggregate, and the excess purchase price over the fair value of net assets of approximately $1.8 million was allocated to goodwill. The results of operations have been included from the respective acquisition dates.

Most of the Company’s business acquisitions have involved additional contingent consideration based upon a multiple of the acquired companies’ respective average EBITDA over a three-year period from the respective date of acquisition. As of December 31, 2005, the maximum additional consideration payable for the Company’s prior acquisitions was approximately $2.4 million, and will be determined and payable through 2008. These amounts are not classified as liabilities under generally accepted accounting principles and are not reflected in the Company’s financial statements until the amounts are fixed and determinable. The Company does not have any other financing arrangements that are not required under generally accepted accounting principles to be reflected in its financial statements. When the amounts are determined, they are capitalized as part of the purchase price of the related acquisition. In January 2005, the Company paid additional consideration of $5.3 million as a result of a prior acquisition, which had been capitalized and accrued in 2004.

(7) Property, Plant and Equipment

A summary of property, plant and equipment at December 31, 2005 and 2004 (in thousands) is as follows:


	2005			2004
Buildings and improvements	$	58,567		$	57,624
Marine vessels and equipment		177,047			193,321
Machinery and equipment		394,582			342,700
Automobiles, trucks, tractors and trailers		9,428			10,248
Furniture and fixtures		13,440			11,944
Construction-in-progress		19,054			2,498
Land		6,581			6,037


		678,699			624,372
Accumulated depreciation		(238,371	)		(193,038	)


Property, plant and equipment, net	$	440,328		$	431,334


Oil and gas assets		119,986			91,104
Accumulated depletion		(25,352	)		(7,287	)

Oil and gas assets, net, under the successful efforts method of accounting	$	94,634		$	83,817

Amounts of property, plant and equipment leased to third parties at December 31, 2005 and 2004 were not material. Depreciation expense (excluding depletion, amortization and accretion) was approximately $68.6 million, $57.1 million and $48.5 million for the years ended December 31, 2005, 2004 and 2003, respectively.

(8)

Investments in Affiliates

On November 2, 2005, the Company’s investment in affiliate sold substantially all of its assets. The Company received $12.5 million as a result of the sale and has recorded receivables of approximately $1.3 million for the remaining proceeds to be distributed. The Company reduced the value of this investment by approximately $1.3 million during 2005 in anticipation of this sale.

(9)

Long-Term Debt

The Company’s long-term debt as of December 31, 2005 and 2004 consisted of the following (in thousands):


	2005		2004
Senior Notes — interest payable semiannually at 8.875%, due May 2011	$	200,000	$	200,000
Term Loans — repaid in November 2005		—		38,500
Revolver — interest payable monthly at floating rate, due in October 2008		—		—
U.S. Government guaranteed long-term financing — interest payable semianually at 6.45%, due in semiannual installments through June 2027		17,406		18,216

		217,406		256,716
Less current portion		810		11,810

Long-term debt	$	216,596	$	244,906

Effective October 31, 2005, the Company amended its bank credit facility to convert the existing term loans and revolving credit facility into a single $150 million revolving credit facility, with an option to increase it to $250 million. Any balance outstanding on the revolving credit facility is due on October 31, 2008. At December 31, 2005, the Company had no balance on this bank credit facility. The credit facility bears interest at a LIBOR rate plus margins that depend on the Company’s leverage ratio. Indebtedness under the credit facility is secured by substantially all of the Company’s assets, including the pledge of the stock of the Company’s principal subsidiaries. The credit facility contains customary events of default and requires that the Company satisfy various financial covenants. It also limits the Company’s capital expenditures, its ability to pay dividends or make other distributions, make acquisitions, make changes to the Company’s capital structure, create liens, incur additional indebtedness or assume additional decommissioning liabilities. The Company also has letters of credit outstanding of approximately $18.6 million at December 31, 2005, which reduce the borrowing availability under its revolving credit facility. At December 31, 2005, the Company was in compliance with all such covenants. The Company wrote-off debt acquisition costs of approximately $224,000 due to the repayment of its term loans. This write-off is included in interest expense in 2005.

The Company has $17.4 million outstanding in U. S. Government guaranteed long-term financing under Title XI of the Merchant Marine Act of 1936, which is administered by the Maritime Administration (MARAD) for two 245-foot class liftboats. The debt bears an interest rate of 6.45% per annum and is payable in equal semi-annual installments of $405,000, which began December 3, 2002, and matures on June 3, 2027. The Company’s obligations are secured by mortgages on the two liftboats. In accordance with the agreement, the Company is required to comply with certain covenants and restrictions, including the maintenance of minimum net worth and debt-to-equity requirements. This long-term financing ranks equally with the bank credit facility as both are secured by unique assets.

The Company also has outstanding $200 million of 8 7/8% unsecured senior notes due 2011. The indenture governing the notes requires semi-annual interest payments, on every November 15^th and May 15^th through the maturity date of May 15, 2011. The Company may redeem the notes during the 12-month period commencing May 15, 2006 at 104.438% of the principal amount redeemed. The indenture governing the senior notes contains certain covenants that, among other things, prevent the Company from incurring additional debt, paying dividends or making other distributions, unless its ratio of cash flow to interest expense is at least 2.25 to 1, except that the Company may incur debt in addition to the senior notes in an amount equal to 30% of its net tangible assets as defined, which was approximately $208 million at December 31, 2005. The indenture also contains covenants that restrict the Company’s ability to create certain liens, sell assets, or enter into certain mergers or acquisitions.

Annual maturities of long-term debt for each of the five fiscal years following December 31, 2005 are as follows (in thousands):


2006	$	810
2007		810
2008		810
2009		810
2010		810
Thereafter		213,356

Total	$	217,406

(10)

Income Taxes

The components of income tax expense (benefit) for the years ended December 31, 2005, 2004 and 2003 are as follows (in thousands):


	2005			2004			2003
Current
Federal	$	30,745		$	87		$	515
State		897			415			245
Foreign		6,087			5,320			2,365


		37,729			5,822			3,125


Deferred
Federal		1,895			17,569			14,561
State		94			105			1,220
Foreign		(1,547	)		(2,440	)		(598	)


		442			15,234			15,183


	$	38,171		$	21,056		$	18,308

Income tax expense differs from the amounts computed by applying the U.S. Federal income tax rate of 35% to income before income taxes as follows (in thousands):


	2005		2004		2003
Computed expected tax expense	$	37,111	$	19,918	$	17,088
Increase resulting from:
State and foreign income taxes		241		178		478
Other		819		960		742


Income tax expense	$	38,171	$	21,056	$	18,308

The significant components of deferred income taxes at December 31, 2005 and 2004 are as follows (in thousands):


	2005		2004
Deferred tax assets:
Allowance for doubtful accounts	$	1,793	$	776
Alternative minimum tax credit and net operating loss carryforward		8,198		12,358
Decommissioning liability		45,106		42,187
Other		9,476		5,133


Net deferred tax assets		64,573		60,454


Deferred tax liabilities:
Property, plant and equipment		137,185		133,710
Note receivable		11,668		14,103
Other		13,707		16,013


Deferred tax liabilities		162,560		163,826


Net deferred tax liability	$	97,987	$	103,372

The net deferred tax assets reflect management’s estimate of the amount that will be realized from future profitability and the reversal of taxable temporary differences that can be predicted with reasonable certainty. A valuation allowance is recognized if it is more likely than not that at least some portion of any deferred tax asset will not be realized.

As of December 31, 2005, the Company has not established a valuation allowance for its deferred tax assets. The Company believes that it is more likely than not that the tax assets will be realized because of the reversal of accelerated tax depreciation and future taxable income.

As of December 31, 2005, the Company has an estimated $5.3 million foreign tax credit carryforward with expiration dates from 2011 through 2014. As of December 31, 2005, the Company also has various state net operating loss carryforwards of an estimated $56 million with expiration dates from 2013 through 2017.

The Company has not provided United States tax expense on earnings of its foreign subsidiaries, since the Company has reinvested or expects to reinvest the undistributed earnings indefinitely. As of December 31, 2005, the undistributed earnings of the Company’s foreign subsidiaries were approximately $22.9 million. If these earnings are repatriated to the United States in the future, additional tax provisions may be required. It is not practicable to estimate the amount of taxes that might be payable on such undistributed earnings.

The American Jobs Creation Act of 2004 was passed on October 22, 2004. This legislation allows, under certain conditions, a one-time tax deduction of 85% of certain foreign earnings that are repatriated prior to the end of the Company’s fiscal 2005 year. The deduction would result in a 5.25% federal tax rate on the repatriated earnings. As of December 31, 2004, the Company had not determined whether earnings will be repatriated or an estimate of the possible United States federal and state income tax expense related to any potential repatriation. In 2005, the Company analyzed foreign earnings that qualified for the temporary repatriation. As a result of the analysis, the Company has determined that there was no significant benefit to the Company from this incentive because foreign tax credits would be available to reduce the impact of repatriation of foreign earnings in future years. Accordingly, the Company did not repatriate any foreign earnings in 2005.

(11)

Stockholders’ Equity

In December 2005, the Company’s Compensation Committee of the Board of Directors granted 24,000 shares of restricted stock to its President. The restricted stock vests in three equal installments on January 2, 2006, 2007 and 2008. The Company expensed approximately $178,000 in 2005 based on the share price of $22.24 on the date of grant and will expense approximately $178,000 in 2006 and 2007, as the remaining shares vest.

In October 2004, the Company sold 9,696,627 shares of common stock that generated net proceeds (before any exercise of the underwriters’ over-allotment option) of approximately $113 million, after deducting underwriting discounts and commissions and the estimated offering expenses. The Company used the net proceeds to repurchase 9,696,627 shares of its common stock from First Reserve Fund VII, Limited Partnership and First Reserve Fund VIII, L.P. The shares repurchased by the Company from the First Reserve funds were retired immediately upon repurchase. In November 2004, an additional 1,454,494 shares of the Company’s common stock were issued pursuant to the exercise of the underwriters’ over-allotment option generating net proceeds of approximately $17 million, after deducting underwriting discounts and commissions.

In 2004, the Superior Energy Services, Inc. 2004 Directors Restricted Stock Units Plan was approved by the Company’s stockholders. This plan provides each non-employee director is granted a number of restricted stock units having an aggregate value of $30,000, with the exact number of units determined by dividing $30,000 by the fair market value of the Company’s common stock on the day of the annual stockholders’ meeting. In addition, upon any person’s initial election or appointment as an eligible director, other than at an annual stockholders’ meeting, such person will receive a pro forma number of restricted stock units based on the number of full calendar months between the date of grant and the first anniversary of the previous annual stockholders’ meeting. A restricted stock unit represents the right to receive from the Company, within 30 days of the date the participant ceases to serve on the Board, one share of the Company’s common stock. As a result of this plan, 19,998 restricted stock units are outstanding at December 31, 2005.

The Company maintains various stock incentive plans, including the 2002 Stock Incentive Plan (2002 Incentive Plan), the 1999 Stock Incentive Plan (1999 Incentive Plan) and the 1995 Stock Incentive Plan (1995 Incentive Plan), as amended. These plans provide long-term incentives to the Company’s key employees, including officers and directors, consultants and advisers (Eligible Participants). Under the 2002 Incentive Plan, the 1999 Incentive Plan and the 1995 Incentive Plan, the Company may grant incentive stock options, non-qualified stock options, restricted

stock, stock awards or any combination thereof to Eligible Participants for up to 1,400,000 shares, 5,929,327 shares and 1,900,000 shares, respectively, of the Company’s common stock. The Compensation Committee of the Company’s Board of Directors establishes the term and the exercise price of any stock options granted under the 2002 Incentive Plan, provided the exercise price may not be less than the fair value of the common share on the date of grant. All of the options which have been granted under the 1995 Stock Incentive Plan are vested.

A summary of stock options granted under the incentive plans for the years ended December 31, 2005, 2004 and 2003 is as follows:


	2005					2004					2003
				Weighted					Weighted					Weighted
	Number of			Average		Number of			Average		Number of			Average
	Shares			Price		Shares			Price		Shares			Price
Outstanding at beginning of year		5,797,295		$	8.43		5,628,000		$	7.53		5,518,516		$	7.33
Granted		863,500		$	17.46		1,490,000		$	10.66		538,000		$	8.94
Exercised		(2,709,624	)	$	6.94		(1,196,060	)	$	7.01		(271,913	)	$	6.72
Forfeited		(57,538	)	$	10.23		(124,645	)	$	8.14		(156,603	)	$	7.00


Outstanding at end of year		3,893,633		$	11.44		5,797,295		$	8.43		5,628,000		$	7.53


Exercisable at end of year		3,759,721		$	11.53		5,328,741		$	8.37		4,248,244		$	7.08


Available for future grants		3,229,784					35,746					1,401,101


Average fair value of grants during the year				$	7.47				$	6.22				$	3.59

A summary of information regarding stock options outstanding at December 31, 2005 is as follows:


	Options Outstanding					Options Exercisable
Range of			Weighted Average	Weighted				Weighted
Exercise			Remaining	Average				Average
Prices	Shares		Contractual Life	Price		Shares		Price

$4.75 - $5.75		33,000	2.7 years	$	5.36		33,000	$	5.36
$7.06 - $9.00		744,610	6.1 years	$	8.38		619,031	$	8.30
$9.10 - $12.45		2,252,523	7.6 years	$	10.23		2,244,190	$	10.23
$12.50 - $17.46		863,500	9.5 years	$	17.46		863,500	$	17.46

(12)

Profit-Sharing Plan

The Company maintains a defined contribution profit-sharing plan for employees who have satisfied minimum service and age requirements. Employees may contribute up to 75% of their earnings to the plans. The Company provides a discretionary match, not to exceed 5% of an employee’s salary. The Company made contributions of approximately $1.9 million, $1.7 million and $1.6 million, in 2005, 2004 and 2003, respectively.

The Company has a nonqualified defined contribution deferred compensation plan which allows certain highly-compensated employees the option to defer up to 75% of their salary and up to 100% of their bonus compensation to the plan. Payments are made after the employee terminates, based on their distribution election and plan balance. Participants earn a return on their deferred compensation that is based on hypothetical investments in certain mutual funds. Changes in market value of these hypothetical participant investments are reflected as an adjustment to the deferred compensation liability of the Company with an offset to compensation expense. As of December 31, 2005, the liability of the Company to the participants was approximately $1.5 million and is recorded in Other Long-Term Liabilities, which reflects the accumulated participant deferrals and earnings as of that date. The Company makes

contributions equal to the participant deferrals into life insurance which is invested in mutual funds similar to the participants’ elections. A change in market value of the life insurance is reflected as an adjustment to the deferred compensation plan asset with an offset to interest income or expense. As of December 31, 2005, the deferred contribution plan asset was approximately $1.4 million and is recorded in Other Long-Term Assets.

(13)

Commitments and Contingencies

The Company leases certain office, service and assembly facilities under operating leases. The leases expire at various dates over the next several years. Total rent expense was approximately $4.3 million in 2005, $4.2 million in 2004 and $2.3 million in 2003. Future minimum lease payments under non-cancelable leases for the five years ending December 31, 2006 through 2010 and thereafter are as follows: $6,360,000, $4,837,000, $2,723,000, $1,667,000, $1,137,000 and $14,181,000, respectively. Future minimum lease payments receivable under non-cancelable sub-leases for the years ending December 31, 2006 through 2008 are as follows: $535,000, $592,000, and $49,000, respectively.

From time to time, the Company is involved in litigation arising out of operations in the normal course of business. In management’s opinion, the Company is not involved in any litigation, the outcome of which would have a material effect on its financial position, results of operations or liquidity.

(14)

Segment Information

Business Segments

The Company’s reportable segments are as follows: well intervention, rental tools, marine, other oilfield services and oil and gas. The first four segments offer products and services within the oilfield services industry. The well intervention segment provides plug and abandonment services, coiled tubing services, well pumping and stimulation services, data acquisition services, gas lift services, electric wireline services, hydraulic drilling and workover services, well control services, engineering support, technical analysis and mechanical wireline services that perform a variety of ongoing maintenance and repairs to producing wells, as well as modifications to enhance the production capacity and life span of the well. The rental tools segment rents and sells specialized equipment for use with onshore and offshore oil and gas well drilling, completion, production and workover activities. The marine segment operates liftboats for production service activities, as well as oil and gas production facility maintenance, construction operations and platform removals. The other oilfield services segment provides contract operations and maintenance services, transportation and logistics services, offshore oil and gas cleaning services, oilfield waste treatment services, dockside cleaning of items, including supply boats, cutting boxes, and process equipment and drilling instrumentation equipment. The oil and gas segment acquires mature oil and gas properties and produces and sells any remaining economic oil and gas reserves prior to the Company’s other segments providing decommissioning services. Oil and gas eliminations represent products and services provided to the oil and gas segment by the Company’s four other segments.

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

Summarized financial information concerning the Company’s segments as of December 31, 2005, 2004 and 2003 and for the years then ended is shown in the following tables (in thousands):


								Other					Oil & Gas
	Well		Rental					Oilfield					Eliminations			Consolid.
2005	Interven.		Tools			Marine		Services			Oil & Gas		& Unallocated			Total

Revenues	$	248,576	$	243,536		$	87,267	$	91,033		$	78,911	$	(13,989	)	$	735,334
Costs of services		142,334		82,562			47,989		71,304			45,804		(13,989	)		376,004
Depreciation, depletion, amortization and accretion		14,481		42,445			8,214		3,654			20,494		—			89,288
General and administrative		53,037		54,533			9,889		17,990			5,540		—			140,989
Reduction in value of assets				—			—		4,850			2,144		—			6,994
Gain on sale of liftboats				—			3,544		—			—		—			3,544
Operating income		38,724		63,996			24,719		(6,765	)		4,929		—			125,603
Interest expense		—		—			—		—			—		(21,862	)		(21,862	)
Interest income		—		—			—		—			1,160		1,041			2,201
Equity in earnings of affiliates		—		1,339			—		—			—		—			1,339
Reduction in value of investment		—		(1,250	)		—		—			—		—			(1,250	)


Income (loss) before income taxes	$	38,724	$	64,085		$	24,719	$	(6,765	)	$	6,089	$	(20,821	)	$	106,031

Identifiable assets	$	280,595	$	405,527		$	203,718	$	52,401		$	147,667	$	7,342		$	1,097,250


Capital expenditures	$	22,524	$	70,227		$	10,399	$	2,323		$	19,693		—		$	125,166


							Other					Oil & Gas
	Well		Rental				Oilfield					Eliminations			Consolid.
2004	Interven.		Tools		Marine		Services			Oil & Gas		& Unallocated			Total

Revenues	$	211,820	$	170,064	$	69,808	$	83,870		$	37,008	$	(8,231	)	$	564,339
Costs of services		122,065		57,353		49,581		67,793			21,547		(8,231	)		310,108
Depreciation, depletion, amortization and accretion		13,546		32,527		7,362		3,889			10,013		—			67,337
General and administrative		43,912		42,165		7,085		14,791			2,652		—			110,605
Operating income		32,297		38,019		5,780		(2,603	)		2,796		—			76,289
Interest expense		—		—		—		—			—		(22,476	)		(22,476	)
Interest income		—		—		—		—			1,648		118			1,766
Equity in earnings of affiliates		—		1,329		—		—			—		—			1,329


Income (loss) before income taxes	$	32,297	$	39,348	$	5,780	$	(2,603	)	$	4,444	$	(22,358	)	$	56,908

Identifiable assets	$	258,870	$	357,762	$	184,928	$	54,561		$	141,179	$	6,613		$	1,003,913


Capital expenditures	$	11,124	$	50,687	$	5,523	$	1,611		$	5,180		—		$	74,125


							Other
	Well		Rental				Oilfield							Consolid.
2003	Interven.		Tools		Marine		Services		Oil & Gas		Unallocated			Total

Revenues	$	187,271	$	141,362	$	70,370	$	100,881	$	741	$	—		$	500,625
Costs of services		111,330		46,119		50,314		81,513		331		—			289,607
Depreciation, depletion, amortization and accretion		12,231		25,696		6,665		4,130		131		—			48,853
General and administrative		39,572		33,457		7,122		14,643		28		—			94,822
Operating income		24,138		36,090		6,269		595		251		—			67,343
Interest expense		—		—		—		—		—		(22,477	)		(22,477	)
Interest income		—		—		—		—		51		158			209
Other income		—		—		2,762		—		—		—			2,762
Equity in earnings of affiliates		—		985		—		—		—		—			985


Income (loss) before income taxes	$	24,138	$	37,075	$	9,031	$	595	$	302	$	(22,319	)	$	48,822

Identifiable assets	$	224,022	$	314,122	$	181,752	$	64,421	$	41,315	$	7,231		$	832,863
Capital expenditures	$	15,248	$	30,192	$	2,043	$	2,692	$	—	$	—		$	50,175

Geographic Segments

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


	Revenues						Long-Lived Assets
	Years Ended December 31,						December 31,
	2005		2004		2003		2005		2004
United States	$	636,062	$	476,771	$	443,936	$	492,602	$	479,812
Other Countries		99,272		87,568		56,689		42,360		35,339


Total	$	735,334	$	564,339	$	500,625	$	534,962	$	515,151

(15)

Interim Financial Information (Unaudited)

The following is a summary of consolidated interim financial information for the years ended December 31, 2005 and 2004 (amounts in thousands, except per share data):


	Three Months Ended
	March 31		June 30		Sept. 30		Dec. 31
2005
Revenues	$	173,247	$	190,000	$	184,101	$	187,986
Gross profit		86,829		99,348		82,704		90,449
Net income		17,209		25,054		9,358		16,238

Earnings per share:
Basic	$	0.22	$	0.32	$	0.12	$	0.20
Diluted		0.22		0.32		0.12		0.20


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

Earnings per share:
Basic	$	0.05	$	0.12	$	0.15	$	0.16
Diluted		0.05		0.12		0.15		0.16

(16)

Supplementary Oil and Natural Gas Disclosures (Unaudited)

The Company’s December 31, 2005 and 2004 estimates of proved reserves are based on reserve reports prepared by DeGolyer and MacNaughton, independent petroleum engineers. The estimates of proved reserves at December 31, 2003 are based on internal reports. Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. This data may also change substantially over time as a result of multiple factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures. Proved reserves are estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

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


	Crude Oil			Natural Gas
	(Mbbls)			(Mmcf)
Proved-developed and undeveloped reserves:
December 31, 2002		—			—
Purchase of reserves in place		193			3,304
Revisions		—			(1	)
Production		(3	)		(79	)


December 31, 2003		190			3,224

Purchase of reserves in place		9,232			17,968
Revisions		88			11,407
Production		(390	)		(3,219	)


December 31, 2004		9,120			29,380

Purchase of reserves in place		168			2,925
Revisions (1)		1,036			(5,294	)
Production		(1,221	)		(3,323	)


December 31, 2005		9,103			23,688


Proved-developed reserves:
December 31, 2003		64			3,190
December 31, 2004		7,731			25,542
December 31, 2005		7,554			21,703

(1) The downward revisions in 2005 were primarily attributable to three factors: 1) the Company determined that it would not undertake four previously planned behind pipe recompletions, 2) one well was plugged and abandoned after experiencing continuing mechanical difficulties, and 3) production rates from several wells after their acquisition by the Company did not support the reserve level initially established.

Costs incurred for oil and natural gas property acquisition and development activities for the years ended December 31, 2005, 2004 and 2003 are as follows (in thousands):


	Years Ended December 31,
	2005		2004		2003
Acquisition of properties — proved	$	9,015	$	81,356	$	5,041
Development costs		19,867		4,707		—


Total costs incurred	$	28,882	$	86,063	$	5,041

Standardized Measure of Discounted Future Net Cash Flows Relating to Reserves

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

The Company believes that the following factors should be taken into account in reviewing the following information: (1) future costs and selling prices will probably differ from those required to be used in these calculations; (2) due to future market conditions and governmental regulations, actual rates of production achieved in future years may vary significantly from the rate of production assumed in the calculations; (3) selection of a 10% discount rate is arbitrary and may not be reasonable as a measure of the relative risk inherent in realizing future net oil and gas revenues; and (4) future net revenues may be subject to different rates of income taxation.

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

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

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


	2005			2004			2003
Future cash inflows	$	792,246		$	587,277		$	26,002
Future production costs		(155,282	)		(148,610	)		(12,603	)
Future development and abandonment costs		(195,415	)		(153,230	)		(6,641	)
Future income tax expense		(171,058	)		(119,567	)		(2,748	)


Future net cash flows after income taxes		270,491			165,870			4,010
10% annual discount for estimated timing of cash flows		65,386			29,363			20


Standardized measure of discounted future net cash flows	$	205,105		$	136,507		$	3,990

A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves for the years ended December 31, 2005, 2004 and 2003 is as follows (in thousands):


	2005			2004			2003
Beginning of the period	$	136,507		$	3,990		$	—
Sales and transfers of oil and natural gas produced, net of production costs		(34,563	)		(15,467	)		(470	)
Net changes in prices and production costs		156,992			949			(1	)
Revisions of quantity estimates		4,314			46,040			(8	)
Development costs incurred		19,867			4,707			—
Changes in estimated development costs		(46,113	)		(99,253	)		(5,496	)
Purchase and sales of reserves in place		18,408			282,935			12,552
Changes in production rates (timing) and other		(25,536	)		(3,238	)		(13	)
Accretion of discount		22,123			656			—
Net change in income taxes		(46,894	)		(84,812	)		(2,574	)


Net increase		68,598			132,517			3,990


End of period	$	205,105		$	136,507		$	3,990

The December 31, 2005 amount was estimated by DeGolyer and MacNaughton using a period-end crude NYMEX price of $61.04 per barrel (bbl), a NYMEX gas price of $9.44 per million British Thermal units, and price differentials provided by the Company. The December 31, 2004 amount was estimated by DeGolyer and MacNaughton using a period-end crude NYMEX price of $43.46 per bbl, a Henry Hub gas price of $6.19 per million British Thermal units, and price differentials provided by the Company. The December 31, 2003 amount was estimated by the Company using a period end oil price of $32.55 per bbl and $6.14 per thousand cubic feet (mcf) for natural gas. The Company had no oil and gas holdings prior to 2003. Spot prices as of February 28, 2006 were $6.71 per million British Thermal units for natural gas and $61.41 per bbl for crude oil.

(17) Accounting Pronouncements

In December 2004, the Financial Accounting Standards Board revised its Statement of Financial Accounting Standards No. 123 (FAS No. 123R), “Accounting for Stock Based Compensation.” Under FAS No. 123R, companies will be required to recognize as expense the estimated fair value of all share-based payments to employees, including the fair value of employee stock options. This expense will be recognized over the period during which the employee is required to provide service in exchange for the award. Pro forma disclosure of the estimated expense impact of such awards is no longer an alternative to expense recognition in the financial statements. FAS No. 123R is effective for public companies in the first annual period beginning after June 15, 2005, and accordingly, the Company will adopt the provisions of FAS No. 123R effective January 1, 2006. The Comapny anticipates using the modified prospective application transition method, which does not include restatement of prior periods. The Company expects to record approximately $89,000 of compensation expense in 2006 due to the adoption of FAS No. 123R for share-based awards granted prior to January 1, 2006. The Company expects the effect of the adoption on future share-based awards to be consistent with the disclosure of pro forma net income and earnings per share as displayed in note 1 of its consolidated financial statements.

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

None.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

Our management has established and maintains a system of disclosure controls and procedures to provide reasonable assurances that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure based closely on the definition of “disclosure controls and procedures” in Rule 13a-15(e) of the Securities Exchange Act of 1934.

Management’s Annual Report on Internal Control Over Financial Reporting

As of December 31, 2005, our management, including our principal executive officer and principal financial officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(e) of the Securities Exchange Act of 1934. Based on this evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures as of December 31, 2005 are effective in providing reasonable assurance that the information required to be disclosed by us in reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Management’s report and the independent registered public accounting firm’s attestation report are included in Item 8 under the captions “Management’s Report on Internal Control over

Financial Reporting” and “Independent Registered Public Accounting Firm’s Report,” and are incorporated herein by reference.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the quarter ended December 31, 2005 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None.

PART III

Item 10. Directors and Executive Officers of the Registrant