EXHIBIT 99.2

Item 8. Financial Statements and Supplementary Data

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 therein.

KPMG LLP

New Orleans, Louisiana
March 8, 2006, except as to
Note 14 which is as of
May 11, 2006

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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.

2

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.

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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.

4

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.

5

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 tools 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 segment. The Company’s inability to continue to perform services for a number of large existing customers, if not offset by sales to new or existing customers, could have a material adverse effect on the Company’s business and financial condition.

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(e) Cash Equivalents

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

(f) Accounts Receivable and Allowances

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

(g) 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.

7

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.

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(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):

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	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.

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(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.

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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.

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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

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(2) Supplemental Cash Flow Information

The following table includes the Company’s supplemental cash flow information for the years ended December 31, 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 (received) 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.

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(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.

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(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

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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

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(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.

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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

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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

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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 modified its segment disclosure by combining its other oilfield services segment into the well intervention segment. In February 2006, the Company sold its environmental subsidiary, which comprised a large part of the other oilfield services segment. The remaining businesses, which include platform and field management services, environmental cleaning services and the sale of drilling instrumentation equipment, are impacted by similar factors that affect the well intervention segment. The combination of the well intervention and other oilfield services segments better reflects the way management evaluates the Company’s results. The prior year segment presentation has been restated to conform to the current segment classification.

The Company’s reportable segments are now as follows: well intervention, rental tools, marine, and oil and gas. The first three 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, drilling instrumentation equipment, contract operations and maintenance services, transportation and logistics services, offshore oil and gas cleaning 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 stabilizers, drill pipe, tubulars and specialized equipment for use with onshore and offshore oil and gas well drilling, completion, production and workover activities. It also provides onsite accommodations and bolting and machining services. The marine segment operates liftboats for production service activities, as well as oil and gas production facility maintenance, construction operations and platform removals. The oil and gas segment acquires mature oil and gas properties and produces and sells any remaining economic oil and gas reserves 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 three other segments.

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

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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):

										Oil & Gas
	Well		Rental							Eliminations			Consolid.
2005	Interven.		Tools			Marine		Oil & Gas		& Unallocated			Total
Revenues	$	339,609	$	243,536		$	87,267	$	78,911	$	(13,989	)	$	735,334
Costs of services		213,638		82,562			47,989		45,804		(13,989	)		376,004
Depreciation, depletion, amortization and accretion		18,135		42,445			8,214		20,494		—			89,288
General and administrative		71,027		54,533			9,889		5,540		—			140,989
Reduction in value of assets		4,850		—			—		2,144		—			6,994
Gain on sale of liftboats		—		—			3,544		—		—			3,544
Operating income		31,959		63,996			24,719		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	$	31,959	$	64,085		$	24,719	$	6,089	$	(20,821	)	$	106,031
Identifiable assets	$	332,996	$	405,527		$	203,718	$	147,667	$	7,342		$	1,097,250
Capital expenditures	$	24,847	$	70,227		$	10,399	$	19,693	$	—		$	125,166

									Oil & Gas
	Well		Rental						Eliminations			Consolid.
2004	Interven.		Tools		Marine		Oil & Gas		& Unallocated			Total
Revenues	$	295,690	$	170,064	$	69,808	$	37,008	$	(8,231	)	$	564,339
Costs of services		189,858		57,353		49,581		21,547		(8,231	)		310,108
Depreciation, depletion, amortization and accretion		17,435		32,527		7,362		10,013		—			67,337
General and administrative		58,703		42,165		7,085		2,652		—			110,605
Operating income		29,694		38,019		5,780		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	$	29,694	$	39,348	$	5,780	$	4,444	$	(22,358	)	$	56,908
Identifiable assets	$	313,431	$	357,762	$	184,928	$	141,179	$	6,613		$	1,003,913
Capital expenditures	$	12,735	$	50,687	$	5,523	$	5,180	$	—		$	74,125

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	Well		Rental									Consolid.
2003	Interven.		Tools		Marine		Oil & Gas		Unallocated			Total
Revenues	$	288,152	$	141,362	$	70,370	$	741	$	—		$	500,625
Costs of services		192,843		46,119		50,314		331		—			289,607
Depreciation, depletion, amortization and accretion		16,361		25,696		6,665		131		—			48,853
General and administrative		54,215		33,457		7,122		28		—			94,822
Operating income		24,733		36,090		6,269		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	$	24,733	$	37,075	$	9,031	$	302	$	(22,319	)	$	48,822
Identifiable assets	$	288,443	$	314,122	$	181,752	$	41,315	$	7,231		$	832,863
Capital expenditures	$	17,940	$	30,192	$	2,043	$	—	$	—		$	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

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(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.

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

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

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

Costs incurred for oil and natural gas property acquisition and development activities for the years ended December 31, 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.

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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

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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 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 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.

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.

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