UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2005

or

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition Period From                    to                   

Commission File No. 0-20310

SUPERIOR ENERGY SERVICES, INC.

(Exact name of registrant as specified in its charter)

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

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

Registrant’s telephone number, including area code: (504) 362-4321

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 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 shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

The number of shares of the registrant’s common stock outstanding on November 1, 2005 was 79,448,760.

1

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Quarterly Report on Form 10-Q for
the Quarterly Period Ended September 30, 2005

TABLE OF CONTENTS

	Page
PART I FINANCIAL INFORMATION
Item 1. Financial Statements		3
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		17
Item 3. Quantitative and Qualitative Disclosures about Market Risk		25
Item 4. Controls and Procedures		25
PART II OTHER INFORMATION
Item 6. Exhibits		26
Officer's Certification Pursuant to Section 302
Officer's Certification Pursuant to Section 302
Officer's Certification Pursuant to Section 906
Officer's Certification Pursuant to Section 906

2

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidated Balance Sheets
September 30, 2005 and December 31, 2004
(in thousands, except share data)

	9/30/05			12/31/04
	(Unaudited)			(Audited)
ASSETS
Current assets:
Cash and cash equivalents	$	81,391		$	15,281
Accounts receivable — net		182,416			156,235
Income taxes receivable		—			2,694
Current portion of notes receivable		4,017			9,611
Prepaid insurance and other		33,482			28,203
Total current assets		301,306			212,024
Property, plant and equipment — net		522,570			515,151
Goodwill — net		224,382			226,593
Notes receivable		28,798			29,131
Investments in affiliates		14,581			14,496
Other assets — net		7,144			6,518
Total assets	$	1,098,781		$	1,003,913
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	39,209		$	36,496
Accrued expenses		69,297			56,796
Income taxes payable		9,167			—
Fair value of commodity derivative instruments		17,588			2,018
Current portion of decommissioning liabilities		10,084			23,588
Current maturities of long-term debt		11,810			11,810
Total current liabilities		157,155			130,708
Deferred income taxes		93,175			103,372
Decommissioning liabilities		107,646			90,430
Long-term debt		236,251			244,906
Other long-term liabilities		1,353			618
Stockholders’ equity:
Preferred stock of $.01 par value. Authorized, 5,000,000 shares; none issued		—			—
Common stock of $.001 par value. Authorized, 125,000,000 shares; issued and outstanding, 79,444,197 shares at September 30, 2005, and 76,766,303 at December 31, 2004		79			77
Additional paid in capital		428,009			398,073
Accumulated other comprehensive income (loss), net		(9,353	)		2,884
Retained earnings		84,466			32,845
Total stockholders’ equity		503,201			433,879
Total liabilities and stockholders’ equity	$	1,098,781		$	1,003,913

See accompanying notes to consolidated financial statements.

3

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidated Statements of Operations
Three and Nine Months Ended September 30, 2005 and 2004
(in thousands, except per share data)
(unaudited)

	Three Months						Nine Months
	2005			2004			2005			2004
Oilfield service and rental revenues	$	162,337		$	138,310		$	470,151		$	380,958
Oil and gas revenues		21,764			14,190			77,197			25,546
Total revenues		184,101			152,500			547,348			406,504
Cost of oilfield services and rentals		90,029			75,871			243,203			212,990
Cost of oil and gas sales		11,368			6,540			35,264			13,270
Total cost of services, rentals and sales		101,397			82,411			278,467			226,260
Depreciation, depletion, amortization and accretion		22,883			17,795			68,860			48,446
General and administrative expenses		37,583			29,637			103,133			79,625
Reduction in value of assets		3,244			—			3,244			—
Gain on sale of liftboats		—			—			3,269			—
Income from operations		18,994			22,657			96,913			52,173
Other income (expense):
Interest expense, net		(5,437	)		(5,651	)		(16,530	)		(16,724	)
Interest income		739			467			1,470			1,365
Equity in income of affiliates, net		558			588			1,336			892
Reduction in value of investment in affiliate		—			—			(1,250	)		—
Income before income taxes		14,854			18,061			81,939			37,706
Income taxes		5,496			6,773			30,318			14,140
Net income	$	9,358		$	11,288		$	51,621		$	23,566
Basic earnings per share	$	0.12		$	0.15		$	0.66		$	0.32
Diluted earnings per share	$	0.12		$	0.15		$	0.65		$	0.31
Weighted average common shares used in computing earnings per share:
Basic		78,707			74,717			77,936			74,469
Incremental common shares from stock options		1,461			969			1,487			743
Diluted		80,168			75,686			79,423			75,212

See accompanying notes to consolidated financial statements.

4

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidated Statements of Cash Flows
Nine Months Ended September 30, 2005 and 2004
(in thousands)
(unaudited)

	2005			2004
Cash flows from operating activities:
Net income	$	51,621		$	23,566
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		68,860			48,446
Deferred income taxes		(2,748	)		9,686
Reduction in value of assets		3,244			—
Equity in income of affiliates		(1,336	)		(892	)
Reduction in value of investment in affiliate		1,250			—
Gain on sale of liftboats		(3,269	)		—
Changes in operating assets and liabilities, net of acquisitions:
Receivables		(18,330	)		(16,346	)
Other — net		1,791			(500	)
Accounts payable		2,924			8,947
Accrued expenses		15,884			18,449
Decommissioning liabilities		(8,199	)		(5,250	)
Income taxes		23,871			(749	)
Net cash provided by operating activities		135,563			85,357
Cash flows from investing activities:
Payments for capital expenditures		(92,960	)		(54,131	)
Acquisitions of businesses, net of cash acquired		(6,435	)		(23,743	)
Acquisitions of oil and gas properties, net of cash acquired		3,686			(14,352	)
Cash proceeds from the sale of liftboats, net		19,313			—
Other		(1,513	)		—
Net cash used in investing activities		(77,909	)		(92,226	)
Cash flows from financing activities:
Principal payments on long-term debt		(8,655	)		(9,855	)
Debt acquisition costs		—			(60	)
Proceeds from exercise of stock options		17,882			7,963
Net cash provided by (used in) financing activities		9,227			(1,952	)
Effect of exchange rate changes on cash		(771	)		(9	)
Net increase (decrease) in cash		66,110			(8,830	)
Cash and cash equivalents at beginning of period		15,281			19,794
Cash and cash equivalents at end of period	$	81,391		$	10,964

See accompanying notes to consolidated financial statements.

5

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements
Nine months Ended September 30, 2005 and 2004

(1) Basis of Presentation

Certain information and footnote disclosures normally in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission; however, management believes the disclosures which are made are adequate to make the information presented not misleading. These financial statements and footnotes should be read in conjunction with the financial statements and notes thereto included in Superior Energy Services, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2004 and Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The financial information of Superior Energy Services, Inc. and subsidiaries (the Company) for the three and nine months ended September 30, 2005 and 2004 has not been audited. However, in the opinion of management, all adjustments (which include only normal recurring adjustments) necessary to present fairly the results of operations for the periods presented have been included therein. The results of operations for the first nine months of the year are not necessarily indicative of the results of operations that might be expected for the entire year. Certain previously reported amounts have been reclassified to conform to the 2005 presentation.

(2) Stock-Based and Long-Term Compensation

The Company accounts for its stock based compensation under the principles prescribed by the Accounting Principles Board’s (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 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 the grant. Stock compensation costs from the grant of restricted stock units are expensed as incurred. 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):

6

	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
Net income, as reported	$	9,358		$	11,288		$	51,621		$	23,566
Stock-based employee compensation expense, net of tax		(2,057	)		(2,375	)		(2,363	)		(2,909	)
Pro forma net income	$	7,301		$	8,913		$	49,258		$	20,657
Basic earnings per share:
Earnings, as reported	$	0.12		$	0.15		$	0.66		$	0.32
Stock-based employee compensation expense, net of tax		(0.03	)		(0.03	)		(0.03	)		(0.04	)
Pro forma earnings per share	$	0.09		$	0.12		$	0.63		$	0.28
Diluted earnings per share:
Earnings, as reported	$	0.12		$	0.15		$	0.65		$	0.31
Stock-based employee compensation expense, net of tax		(0.03	)		(0.03	)		(0.03	)		(0.04	)
Pro forma earnings per share	$	0.09		$	0.12		$	0.62		$	0.27
Black-Scholes option pricing model assumptions:
Risk free interest rate		*			4.28	%		3.85	%		4.28	%
Expected life (years)		*			5			6			5
Volatility		*			65.22	%		38.91	%		65.22	%
Dividend yield		*			—			—			—

(*There were no stock option grants during the three months ended September 30, 2005.)

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.

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 $535,000 for the three and nine months ended September 30, 2005.

(3) 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

7

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 that would have a dilutive effect on earnings per share.

(4) Reduction in Value of Assets

During the quarter ended September 30, 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 quarter ended September 30, 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.

(5) Gain on Sale of Liftboats

During the quarter ended June 30, 2005, the Company sold 17 of its rental liftboats with leg-lengths from 105 feet to 135 feet for $19.5 million in cash (exclusive 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 $3.3 million as a result of this transaction.

(6) Investment in Affiliate

The Company believes there was an other-than-temporary decline in the value of its investment in an affiliate and reduced the value of its investment by approximately $1.3 million during the quarter ended June 30, 2005.

Subsequent Event

On November 2, 2005, the Company’s investment in affiliate sold substantially all of its assets. The Company expects to receive approximately $13 million as a result of the sale. Any gain or loss as a result of the sale is not expected to be material and will be recognized in the fourth quarter of 2005.

(7) Acquisitions

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.

8

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 September 30, 2005, the maximum additional consideration payable for the Company’s prior acquisitions was approximately $3.2 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 the nine months ended September 30, 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.

(8) 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.

Summarized financial information concerning the Company’s segments for the three and nine months ended September 30, 2005 and 2004 is shown in the following tables (in thousands):

9

Three Months Ended September 30, 2005

							Other					Oil & Gas
	Well		Rental				Oilfield					Eliminations			Consolid.
	Interven.		Tools		Marine		Services			Oil & Gas		& Unallocated			Total
Revenues	$	63,361	$	61,686	$	18,467	$	22,487		$	21,764	$	(3,664	)	$	184,101
Cost of services, rentals and sales		41,860		21,992		11,839		18,002			11,368		(3,664	)		101,397
Depreciation, depletion, amortization and accretion		3,680		10,970		1,987		909			5,337		—			22,883
General and administrative expense		14,400		13,913		2,497		5,401			1,372		—			37,583
Reduction in value of assets		—		—		—		1,100			2,144		—			3,244
Income (loss) from operations		3,421		14,811		2,144		(2,925	)		1,543		—			18,994
Interest expense, net		—		—		—		—			—		(5,437	)		(5,437	)
Interest income		—		—		—		—			294		445			739
Equity in income of affiliates, net		—		558		—		—			—		—			558
Income (loss) before income taxes	$	3,421	$	15,369	$	2,144	$	(2,925	)	$	1,837	$	(4,992	)	$	14,854

Three Months Ended September 30, 2004

							Other					Oil & Gas
	Well		Rental				Oilfield					Eliminations			Consolid.
	Interven.		Tools		Marine		Services			Oil & Gas		& Unallocated			Total
Revenues	$	59,861	$	42,530	$	18,049	$	20,354		$	14,190	$	(2,484	)	$	152,500
Cost of services, rentals and sales		34,342		15,344		12,193		16,476			6,540		(2,484	)		82,411
Depreciation, depletion, amortization and accretion		3,468		8,158		1,856		1,035			3,278		—			17,795
General and administrative expense		11,891		10,886		1,886		4,045			929		—			29,637
Income (loss) from operations		10,160		8,142		2,114		(1,202	)		3,443		—			22,657
Interest expense, net		—		—		—		—			—		(5,651	)		(5,651	)
Interest income		—		—		—		—			434		33			467
Equity in income of affiliates, net		—		588		—		—			—		—			588
Income (loss) before income taxes	$	10,160	$	8,730	$	2,114	$	(1,202	)	$	3,877	$	(5,618	)	$	18,061

10

Nine Months Ended September 30, 2005

								Other					Oil & Gas
	Well		Rental					Oilfield					Eliminations			Consolid.
	Interven.		Tools			Marine		Services			Oil & Gas		& Unallocated			Total
Revenues	$	182,348	$	175,435		$	56,550	$	68,635		$	77,197	$	(12,817	)	$	547,348
Cost of services, rentals and sales		107,721		58,403			36,235		53,661			35,264		(12,817	)		278,467
Depreciation, depletion, amortization and accretion		11,060		31,340			6,107		2,633			17,720		—			68,860
General and administrative expense		38,905		39,534			6,712		13,547			4,435		—			103,133
Reduction in value of assets		—		—			—		1,100			2,144		—			3,244
Gain on sale of liftboats		—		—			3,269		—			—		—			3,269
Income (loss) from operations		24,662		46,158			10,765		(2,306	)		17,634		—			96,913
Interest expense, net		—		—			—		—			—		(16,530	)		(16,530	)
Interest income		—		—			—		—			849		621			1,470
Equity in income of affiliates, net		—		1,336			—		—			—		—			1,336
Reduction in value of investment		—		(1,250	)		—		—			—		—			(1,250	)
Income (loss) before income taxes	$	24,662	$	46,244		$	10,765	$	(2,306	)	$	18,483	$	(15,909	)	$	81,939

Nine Months Ended September 30, 2004

							Other					Oil & Gas
	Well		Rental				Oilfield					Eliminations			Consolid.
	Interven.		Tools		Marine		Services			Oil & Gas		& Unallocated			Total
Revenues	$	149,041	$	125,093	$	49,352	$	63,081		$	25,546	$	(5,609	)	$	406,504
Cost of services, rentals and sales		88,440		42,113		36,482		51,564			13,270		(5,609	)		226,260
Depreciation, depletion, amortization and accretion		10,189		23,395		5,410		2,929			6,523		—			48,446
General and administrative expense		31,095		30,581		5,141		11,147			1,661		—			79,625
Income (loss) from operations		19,317		29,004		2,319		(2,559	)		4,092		—			52,173
Interest expense, net		—		—		—		—			—		(16,724	)		(16,724	)
Interest income		—		—		—		—			1,283		82			1,365
Equity in income of affiliates, net		—		892		—		—			—		—			892
Income (loss) before income taxes	$	19,317	$	29,896	$	2,319	$	(2,559	)	$	5,375	$	(16,642	)	$	37,706

Identifiable Assets

							Other
	Well		Rental				Oilfield						Consolidated
	Interven.		Tools		Marine		Services		Oil & Gas		Unallocated		Total
September 30, 2005	$	275,334	$	426,853	$	176,990	$	55,071	$	157,274	$	7,259	$	1,098,781
December 31, 2004	$	258,870	$	357,762	$	184,928	$	54,561	$	141,179	$	6,613	$	1,003,913

Geographic Segments

The Company attributes revenue to countries based on the location 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 the United States or other countries based on the physical location of the asset at the end of a period. The Company’s information by geographic area is as follows (amounts in thousands):

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	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
Revenues:
United States	$	159,858	$	129,614	$	479,485	$	346,993
Other Countries		24,243		22,886		67,863		59,511
Total	$	184,101	$	152,500	$	547,348	$	406,504

	September 30,		December 31,
	2005		2004
Long-Lived Assets:
United States	$	484,144	$	479,812
Other Countries		38,426		35,339
Total	$	522,570	$	515,151

(9) Debt

The Company has a bank credit facility consisting of term loans in an aggregate amount of $30.3 million outstanding at September 30, 2005, and a revolving credit facility of $75 million, none of which was outstanding at September 30, 2005. The term loans require principal payments of $2.8 million each quarter through June 30, 2008. Any balance outstanding on the revolving credit facility is due on August 13, 2006. 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. During the quarter ended September 30, 2005, the Company amended the bank credit facility to increase the capital expenditure limitation for 2005 from $60 million to $110 million. The Company also has letters of credit outstanding of approximately $11.1 million at September 30, 2005, which reduce the borrowing availability under its revolving credit facility. At September 30, 2005, the Company was in compliance with all such covenants, as amended.

The Company has $17.8 million outstanding in U. S. Government guaranteed long-term financing under Title XI of the Merchant Marine Act of 1936, which is administered by the Maritime Administration (MARAD), for two 245-foot class liftboats. The debt bears interest at 6.45% per annum and is payable in equal semi-annual installments of $405,000, on every June 3rd and December 3rd through June 3, 2027. The Company’s obligations are secured by mortgages on the two liftboats. In accordance with this agreement, the Company is required to comply with certain covenants and restrictions, including the maintenance of minimum net worth and debt-to-equity requirements. At September 30, 2005, the Company was in compliance with all such covenants. This long-term financing ranks equally with the bank credit facility.

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 May 15^th and November 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 additional debt in addition to the senior notes in an amount equal to 30% of its net tangible assets as defined, which was approximately $202 million at September 30, 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. At September 30, 2005, the Company was in compliance with all such covenants.

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Subsequent Event

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.

(10) 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 its exposure to fluctuations in the price of oil. The Company does not enter into derivative 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 September 30, 2005. The Company uses financially-settled crude oil swaps and zero-cost collars that provide floor and ceiling prices with varying upside price participation. 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 revenue. For the nine months ended September 30, 2005, hedging settlement payments reduced oil revenues by approximately $6.5 million, and gains or losses recognized due to hedge ineffectiveness were immaterial.

The Company had the following hedging contracts as of September 30, 2005:

Crude Oil Positions
	Instrument	Strike	Volume (Bbls)
Remaining Contract Term	Type	Price (Bbl)	Daily	Total (Bbls)
10/05 - 8/06	Swap	$39.45	1,000 - 1,050	368,413
10/05 - 8/06	Collar	$35.00/$45.60	1,000 - 1,050	368,413

Based on the futures prices quoted at September 30, 2005, the Company expects to reclassify net losses of approximately $11.1 million, net of taxes, into earnings related to the derivative contracts during the next twelve months; however, actual gains or losses recognized may differ materially depending on the movement of commodity pricing over the next twelve months.

(11) Decommissioning Liabilities

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 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, including pipeline, 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 restore the sites of its oil and gas properties, and uses that estimate to record its proportionate share of the decommissioning liability. In

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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 liabilities whenever indicators suggest that the estimated cash flows needed to satisfy the liability have changed materially. The timing and amounts of these cash flows are estimates, and changes to these estimates may result in additional (or decreased) liabilities recorded, which in turn would increase (or decrease) the carrying values of the related oil and gas properties. The following table summarizes the activity for the Company’s decommissioning liabilities for the nine months ended September 30, 2005 and 2004 (amounts in thousands):

	Nine Months Ended
	September 30,
	2005			2004
Total decommissioning liabilities at December 31, 2004 and 2003, respectively	$	114,018		$	38,853
Liabilities acquired and incurred		11,494			53,642
Liabilities settled		(8,199	)		(5,250	)
Accretion		3,290			1,939
Revision in estimated liabilities		(2,873	)		(1,576	)
Total decommissioning liabilities at September 30, 2005 and 2004, respectively		117,730			87,608
Current portion of decommissioning liabilities at September 30, 2005 and 2004, respectively		10,084			10,766
Long-term portion of decommissioning liabilities at September 30, 2005 and 2004, respectively	$	107,646		$	76,842

(12) Notes Receivable

Notes receivable consist primarily of commitments from the sellers of oil and gas properties for the abandonment of the acquired properties. The Company invoices the seller agreed upon amounts during the course of decommissioning (abandonment and structure removal) in accordance with the applicable agreements with the seller. These receivables are recorded at present value, and the related discounts are amortized to interest income, based on the expected timing of the decommissioning.

(13) Other Comprehensive Income

The following tables reconcile the change in accumulated other comprehensive income (loss) for the three and nine months ended September 30, 2005 and 2004 (amounts in thousands):

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	Three Months Ended
	September 30,
	2005			2004
Accumulated other comprehensive income (loss), June 30, 2005 and 2004, respectively	$	(6,865	)	$	2,892
Other comprehensive income (loss):
Other comprehensive loss, net of tax
Hedging activities:
Adjustment for settled contracts, net of tax of $1,294 in 2005		2,203			—
Changes in fair value of outstanding hedging positions, net of tax of ($2,232) in 2005 and ($2,104) in 2004		(3,800	)		(3,583	)
Foreign currency translation adjustment, net of tax of ($523) in 2005 and ($59) in 2004		(891	)		(99	)
Total other comprehensive income (loss)		(2,488	)		(3,682	)
Accumulated other comprehensive income (loss), September 30, 2005 and 2004, respectively	$	(9,353	)	$	(790	)

	Nine Months Ended
	September 30,
	2005			2004
Accumulated other comprehensive income, December 31, 2004 and 2003, respectively	$	2,884		$	264
Other comprehensive income (loss):
Other comprehensive loss, net of tax
Hedging activities:
Adjustment for settled contracts, net of tax of $2,397 in 2005		4,080			—
Changes in fair value of outstanding hedging positions, net of tax of ($7,929) in 2005 and ($2,104) in 2004		(13,499	)		(3,583	)
Foreign currency translation adjustment, net of tax of ($1,654) in 2005 and $1,676 in 2004		(2,818	)		2,529
Total other comprehensive income (loss)		(12,237	)		(1,054	)
Accumulated other comprehensive income (loss), September 30, 2005 and 2004, respectively	$	(9,353	)	$	(790	)

(14) Commitments and Contingencies

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

(15) 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.” The revision establishes standards for the accounting of transactions in which an entity exchanges its equity instruments for goods or services, particularly transactions in which an entity obtains employee services in share-based payment transactions. The revised statement requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. That cost is to be recognized over the period during which the employee is required to provide service in exchange for the award. Changes in fair value

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during the requisite service period are to be recognized as compensation cost over that period. In addition, the revised statement amends Statement of Financial Accounting Standards No. 95, “Statement of Cash Flows,” to require that excess tax benefits be reported as a financing cash flow rather than as a reduction of taxes paid. The Company plans to adopt FAS No. 123R effective January 1, 2006. The Company is currently assessing the expected impact on its consolidated 2006 financial statements.

In March 2005, the Financial Accounting Standards Board issued FASB Interpretation No. 47 (FIN No. 47), “Accounting for Conditional Asset Retirement Obligations — an interpretation of FASB Statement No. 143.” FIN No. 47 clarifies that FASB Statement No. 143, “Accounting for Asset Retirement Obligations,” requires that an entity recognize a liability for the fair value of a conditional asset retirement obligation when incurred if the liability’s fair value can be reasonably estimated. FIN No. 47 is effective no later than the end of fiscal years ending after December 15, 2005. The Company does not expect the adoption of FIN No. 47 to have a material impact on 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” and changes the requirements for the accounting for, and reporting of, a change in accounting principle. This Statement applies to all voluntary changes in accounting principle. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. When a pronouncement includes specific transition provisions, those provisions should be followed. The Statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The Company does not expect the adoption of FAS No. 154 to have a material impact on its consolidated financial statements.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Forward-Looking Statements

The following management’s discussion and analysis of financial condition and results of operations contains forward-looking statements which involve risks and uncertainties. All statements other than statements of historical fact included in this section regarding our financial position and liquidity, strategic alternatives, future capital needs, business strategies and other plans and objectives of our management for future operations and activities, are forward-looking statements. These statements are based on certain assumptions and analyses made by our management in light of its experience and its perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate under the circumstances. Such forward-looking statements are subject to uncertainties that could cause our actual results to differ materially from such statements. Such uncertainties include but are not limited to: the volatility of the oil and gas industry, including the level of offshore exploration, production and development activity; changes in competitive factors affecting our operations; risks associated with the acquisition of mature oil and gas properties, including estimates of recoverable reserves, future oil and gas prices and potential environmental and plugging and abandonment liabilities; seasonality of the offshore industry in the Gulf of Mexico and the long-term effects of Hurricanes Katrina and Rita; our dependence on key personnel and certain customers; operating hazards, including the significant possibility of accidents resulting in personal injury, property damage or environmental damage; the volatility and risk associated with oil and gas prices; risks of our growth strategy, including the risks of rapid growth and the risks inherent in acquiring businesses and mature oil and gas properties; the effect on our performance of regulatory programs and environmental matters and risks associated with international expansion, including political and economic uncertainties. These and other uncertainties related to our business are described in detail in our Annual Report on Form 10-K for the year ended December 31, 2004. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof. We undertake no obligation to update any of our forward-looking statements for any reason.

Executive Summary

The high levels of activity prior to the hurricanes suggested we were on a pace to establish our highest ever quarterly revenues, income from operations and net income. However, the active hurricane season, highlighted by the lingering impact from Hurricanes Katrina and Rita created lost or deferred revenue and resulted in higher expenses. As a result, third quarter revenues were $184.1 million, income from operations was $19.0 million and net income was $9.4 million, or $0.12 diluted earnings per share. We estimate the overall impact from these hurricanes and other weather disruptions during the third quarter was a reduction in diluted earnings per share of between $0.20 and $0.22.

We recorded non-cash charges of $3.2 million for the reduction in value of certain assets including a $2.1 million write down in value of reserves on two of our oil and gas properties and a $1.1 million write down of assets in the other oilfield services segment as a result of our decision to sell the remaining inventory of our oil spill response business. We wrote down the value of two mature properties due to well issues affecting production rates and operating costs. Earlier this year we successfully restored production from wells at those properties after years of being shut-in. However, we determined that it would be uneconomical to perform additional production enhancement work to maintain production.

We experienced increased demand for production-related services such as coiled tubing and hydraulic workover services, higher utilization of our liftboats, increased rentals of drilling-related tools and accessories and record levels of oil and gas production prior to Hurricane Katrina when compared to the second quarter of 2005 and third quarter of 2004.

Despite the unprecedented impact on activity during this year’s hurricane season, revenues increased over the second quarter of 2005 and the third quarter of 2004 for the well intervention, marine and rental tools segment. We estimate that our hurricane-related lost revenue opportunity was in the range of $32.0 million to $35.0 million.

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In addition to stronger Gulf of Mexico activity levels, the revenue growth in the well intervention and rental tools segments were due in part to our continued diversification on land and international markets.

Expenses directly related to Hurricanes Katrina and Rita during the third quarter are approximately $6.5 million, including $2.0 million in equipment and facility losses and repairs, $2.0 million in relief aid to more than 560 employees affected by Hurricanes Katrina or Rita, $1.5 million in storm-related payroll expenses, temporary lodging and miscellaneous expenses and $1.0 million in repairs to our oil and gas platforms. We anticipate an additional $5.0 million to $6.0 million in hurricane-related expenses in the fourth quarter, mainly to complete repairs on our oil and gas platforms.

Three of our oil and gas properties suffered significant damage – South Pass 60, Ship Shoal 253 and West Delta 79/80. Repairs have since been completed at West Delta 79/80, and production from all fields, with the exception of South Pass 60 and Ship Shoal 253, is expected to be brought on-line once third-party pipelines, processing plants and refineries can accept production. We anticipate production from South Pass 60 and Ship Shoal 253 should resume prior to year-end.

The hurricane season resulted in unprecedented damage to the energy industry’s Gulf of Mexico infrastructure. It is estimated that more than 100 platforms were destroyed, more than 50 platforms were substantially damaged and more than 20 drilling rigs were destroyed. In addition, oil and gas production has been slowly returning to pre-storm levels after most Gulf of Mexico production was shut-in beginning in late August due to damage to pipelines, processing facilities and refineries.

We believe restoring the Gulf of Mexico energy industry to pre-hurricane status will require multiple phases, including damage assessment; project planning and engineering; platform recovery, salvage and abandonment, as needed; well recovery and abandonment; production restoration; and the resumption of drilling activity. We believe we are well positioned to participate in all phases of oil and gas restoration work in the Gulf of Mexico.

Comparison of the Results of Operations for the Three Months Ended September 30, 2005 and 2004

For the three months ended September 30, 2005, our revenues were $184.1 million, resulting in net income of $9.4 million or $0.12 diluted earnings per share. For the three months ended September 30, 2004, revenues were $152.5 million and net income was $11.3 million or $0.15 diluted earnings per share. We experienced higher revenue and higher gross margin in most of our segments, especially our rental tools and oil and gas segments. Despite our higher revenue and gross margin, we had lower net income and diluted earnings per share primarily as a result of storm-related costs and the reduction in value of assets.

The following table compares our operating results for the three months ended September 30, 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	$	63,361		$	59,861		$	3,500		$	21,501		34	%	$	25,519		43	%	$	(4,018	)
Rental Tools		61,686			42,530			19,156			39,694		64	%		27,186		64	%		12,508
Marine		18,467			18,049			418			6,628		36	%		5,856		32	%		772
Other Oilfield Services		22,487			20,354			2,133			4,485		20	%		3,878		19	%		607
Oil and Gas		21,764			14,190			7,574			10,396		48	%		7,650		54	%		2,746
Less: Oil and Gas Elim.		(3,664	)		(2,484	)		(1,180	)		—		—			—		—			—
Total	$	184,101		$	152,500		$	31,601		$	82,704		45	%	$	70,089		46	%	$	12,615

The following discussion analyzes our results on a segment basis.

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Well Intervention Segment

Revenue for our well intervention segment was $63.4 million for the three months ended September 30, 2005, as compared to $59.9 million for the same period in 2004. This segment’s gross margin percentage declined to 34% for the three months ended September 30, 2005 from 43% for the same period of 2004. We experienced higher revenue for most of our production-related services, especially well control, coiled tubing, hydraulic workover and wireline services, as production-related activity improved in the Gulf of Mexico. These increases were partially offset by lower plug and abandonment revenue. The decrease in the gross margin is the result of increased costs related to weather delays and storm-related costs.

Rental Tools Segment

Revenue for our rental tools segment for the three months ended September 30, 2005 was $61.7 million, a 45% increase over the same period in 2004. The gross margin percentage remained unchanged at 64% for the three months ended September 30, 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. Our international revenue for the rental tools segment has increased 61% to approximately $15.4 million for the quarter ended September 30, 2005 over the same period of 2004. Our biggest improvements were in the North Sea, Trinidad, Venezuela and Mexico.

Marine Segment

Our marine segment revenue for the three months ended September 30, 2005 increased 2% over the same period in 2004 to $18.5 million. The gross margin percentage for the three months ended September 30, 2005 increased to 36% from 32% for the same period in 2004. Effective June 1, 2005, we sold our 17 rental liftboats in the 105-foot and the 120 to 135-foot classes. The increase in revenue is caused by increased utilization of our fleet’s remaining larger liftboats at higher dayrates offset by fewer liftboats generating revenue. 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 44% to approximately $9,526 in the third quarter of 2005 from $6,622 in the third quarter of 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 76% for the third quarter of 2005 from 69% in the same period in 2004.

Other Oilfield Services Segment

Revenue from our other oilfield services segment for the three months ended September 30, 2005 was $22.5 million, a 10% increase over the $20.4 million in revenue for the same period in 2004. The gross margin percentage increased slightly to 20% in the three months ended September 30, 2005 from 19% in the same period in 2004. The revenue increase is primarily due to increased demand for our waste disposal and field management services. The increase in the segment’s gross margin percentage is due to this increased demand as well as cost saving efforts in our waste disposal services.

Oil and Gas Segment

Oil and gas revenues were $21.8 million in the three months ended September 30, 2005, as compared to $14.2 million in the same period of 2004. The increase in revenue is primarily the result of production from South Pass 60, which was acquired in late-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 third quarter of 2005, production was approximately 426,800 boe, as compared to approximately 335,900 boe in the third quarter of 2004. The gross margin percentage decreased to 48% in the three months ended September 30, 2005 from 54% in the same period of 2004. This decrease in the gross margin percentage is primarily caused by the higher costs to operate our additional oil and gas properties as well as significant deferred revenue from storm-related down-time of production.

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Depreciation, Depletion, Amortization and Accretion

Depreciation, depletion, amortization and accretion increased to $22.9 million in the three months ended September 30, 2005 from $17.8 million in the same period in 2004. The increase is primarily the result of additional 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 Expenses

General and administrative expenses increased to $37.6 million for the three months ended September 30, 2005 from $29.6 million for the same period in 2004. Of this increase, $4.5 million is the result of storm-related costs from Hurricanes Katrina and Rita including $1.5 million in equipment and facility losses and repairs, $2.0 million in relief aid to more than 560 employees affected by Hurricanes Katrina or Rita, and $1.0 million in storm-related payroll expenses, temporary lodging and miscellaneous expenses. The remaining increase was primarily related to increased payroll expense and bonus accruals, 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 quarter ended September 30, 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. Also during the quarter ended September 30, 2005, 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.

Comparison of the Results of Operations for the Nine Months Ended September 30, 2005 and 2004

For the nine months ended September 30, 2005, our revenues were $547.3 million, resulting in net income of $51.6 million or $0.65 diluted earnings per share. For the nine months ended September 30, 2004, revenues were $406.5 million and net income was $23.6 million or $0.31 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.

The following table compares our operating results for the nine months ended September 30, 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	$	182,348		$	149,041		$	33,307		$	74,627		41	%	$	60,601		41	%	$	14,026
Rental Tools		175,435			125,093			50,342			117,032		67	%		82,980		66	%		34,052
Marine		56,550			49,352			7,198			20,315		36	%		12,870		26	%		7,445
Other Oilfield Services		68,635			63,081			5,554			14,974		22	%		11,517		18	%		3,457
Oil and Gas		77,197			25,546			51,651			41,933		54	%		12,276		48	%		29,657
Less: Oil and Gas Elim.		(12,817	)		(5,609	)		(7,208	)		—		—			—		—			—
Total	$	547,348		$	406,504		$	140,844		$	268,881		49	%	$	180,244		44	%	$	88,637

The following discussion analyzes our results on a segment basis.

20

Well Intervention Segment

Revenue for our well intervention segment was $182.3 million for the nine months ended September 30, 2005, as compared to $149.0 million for the same period in 2004. This segment’s gross margin percentage remained unchanged at 41% for the nine months ended September 30, 2005 and 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, wireline and coiled tubing services.

Rental Tools Segment

Revenue for our rental tools segment for the nine months ended September 30, 2005 was $175.4 million, a 40% increase over the same period in 2004. The gross margin percentage increased slightly to 67% for the nine months ended September 30, 2005 compared to 66% for the same period of 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. Our international revenue for the rental tools segment has increased 45% to approximately $37.4 million for the nine months ended September 30, 2005 from the same period of 2004. Our biggest improvements were in the North Sea, Trinidad, Venezuela and Mexico.

Marine Segment

Our marine segment revenue for the nine months ended September 30, 2005 increased 15% over the same period in 2004 to $56.6 million. The gross margin percentage for the nine months ended September 30, 2005 increased to 36% from 26% for the same period in 2004. The nine months ended September 30, 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 four 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 29% to approximately $7,788 in the nine months ended September 30, of 2005 from $6,019 in the same period of 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 also increased to approximately 75% for the nine months ended September 30, of 2005 from 70% in the same period in 2004.

Other Oilfield Services Segment

Revenue from our other oilfield services segment for the nine months ended September 30, 2005 was $68.6 million, a 9% increase over the $63.1 million in revenue for the same period in 2004. The gross margin percentage increased to 22% in the nine months ended September 30, 2005 from 18% in the same period 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 this increased demand as well as cost saving efforts in our waste disposal services.

Oil and Gas Segment

Oil and gas revenues were $77.2 million in the nine months ended September 30, 2005 as compared to $25.5 million in the same period of 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 nine months ended September 30, 2005, production was approximately 1,690,000 boe as compared to approximately 628,600 boe in the same period of 2004. The gross margin percentage increased to 54% in the nine months ended September 30, 2005 from 48% in the same period of 2004. This increase is primarily the result of higher commodity prices.

Depreciation, Depletion, Amortization and Accretion

Depreciation, depletion, amortization and accretion increased to $68.9 million in the nine months ended September 30, 2005 from $48.4 million in the same period in 2004. The increase is primarily a result of depletion and accretion

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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 Expenses

General and administrative expenses increased to $103.1 million for the nine months ended September 30, 2005 from $79.6 million for the same period in 2004. Of this increase, $4.5 million is the result of storm related costs from Hurricanes Katrina and Rita in the third quarter of 2005 including $1.5 million in equipment and facility losses and repairs, $2.0 million in relief aid to more than 560 employees affected by the hurricanes and $1.0 million in storm-related payroll expenses, temporary lodging and miscellaneous expenses. The remaining increase was primarily related to increased payroll expense and bonus accruals, increased insurance costs and expenses as a result of our growth, oil and gas acquisitions and geographic expansion. General and administrative expenses decreased to 19% of revenue for the nine months ended September 30, 2005 from 20% for the same period in 2004.

Reduction in Value of Assets

During the quarter ended September 30, 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. Also during the quarter ended September 30, 2005, 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.

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 $19.5 million in cash (exclusive of costs to sell), which resulted in a gain of $3.3 million.

Liquidity and Capital Resources

In the nine months ended September 30, 2005, we generated net cash from operating activities of $135.6 million as compared to $85.4 million in the same period of 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 $81.4 million at September 30, 2005 compared to $15.3 million at December 31, 2004.

We made $93.0 million of capital expenditures during the nine months ended September 30, 2005, of which approximately $49.1 million was used to expand and maintain our rental tool equipment inventory. We also made $17.2 million of capital expenditures in our oil and gas segment and $23.8 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. In addition, we made $2.9 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 $22 million. This amount does not include any future change orders, barge outfitting or mobilization costs. Progress payments are 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 September 30, 2005, the total amount of progress payments made on the crane was approximately $6.7 million.

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We currently believe that we will make approximately $15 to $20 million of capital expenditures, excluding acquisitions and targeted asset purchases, during the remaining three months of 2005 primarily to further expand our rental tool asset base and perform workovers on SPN Resources oil and gas properties. We believe that our current working capital, cash generated from our operations and availability under our revolving credit facility will provide sufficient funds for our identified capital projects.

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

We have a bank credit facility consisting of term loans in an aggregate amount of $30.3 million outstanding at September 30, 2005 and a revolving credit facility of $75 million, none of which was outstanding at September 30, 2005. 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. The credit facility bears interest at a LIBOR rate plus margins that depend on the Company’s leverage ratio. As of November 4, 2005, there was no balance outstanding on this amended 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.

We have $17.8 million outstanding at September 30, 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 $202 million at September 30, 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 September 30, 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 $32.8 million, when decommissioning operations are performed. We do not have any other material obligations or commitments.

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	Remaining
	Three
	Months
Description	2005		2006		2007		2008		2009		2010		Thereafter
Long-term debt, including estimated interest payments	$	13,049	$	32,045	$	31,345	$	25,186	$	19,513	$	19,461	$	229,549
Decommissioning liabilities		5,287		13,828		20,209		8,628		3,327		12,628		53,823
Operating leases		1,600		5,861		3,940		2,056		1,167		1,009		14,636
Derrick barge construction		445		15,009		—		—		—		—		—
Total	$	20,381	$	66,743	$	55,494	$	35,870	$	24,007	$	33,098	$	298,008

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 September 30, 2005, the maximum additional consideration payable for our prior acquisitions was approximately $3.2 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 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.

New 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.” The revision establishes standards for the accounting of transactions in which an entity exchanges its equity instruments for goods or services, particularly transactions in which an entity obtains employee services in share-based payment transactions. The revised statement requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. That cost is to be recognized over the period during which the employee is required to provide service in exchange for the award. Changes in fair value during the requisite service period are to be recognized as compensation cost over that period. In addition, the revised statement amends Statement of Financial Accounting Standards No. 95, “Statement of Cash Flows,” to require that excess tax benefits be reported as a financing cash flow rather than as a reduction of taxes paid. We plan to adopt FAS No. 123R effective January 1, 2006. We are currently assessing the expected impact on our consolidated 2006 financial statements.

In March 2005, the Financial Accounting Standards Board issued FASB Interpretation No. 47 (FIN No. 47), “Accounting for Conditional Asset Retirement Obligations — an interpretation of FASB Statement No. 143.” FIN No. 47 clarifies that FASB Statement No. 143, “Accounting for Asset Retirement Obligations,” requires that an entity recognize a liability for the fair value of a conditional asset retirement obligation when incurred if the liability’s fair value can be reasonably estimated. FIN No. 47 is effective no later than the end of fiscal years ending after December 15, 2005. We do not expect the adoption of FIN No. 47 to have a material impact on our 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” and changes the requirements for the accounting for, and reporting of, a change in accounting principle. This Statement applies to all voluntary changes in accounting principle. It also applies to changes required by an

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accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. When a pronouncement includes specific transition provisions, those provisions should be followed. The Statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. We do not expect the adoption of FAS No. 154 to have a material impact on our consolidated financial statements.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

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

We use derivative commodity instruments to manage commodity price risks associated with future oil and natural gas production. As of September 30, 2005, we had the following contracts in place:

Crude Oil Positions
	Instrument	Strike	Volume (Bbls)
Remaining Contract Term	Type	Price (Bbl)	Daily	Total (Bbls)
10/05 - 8/06	Swap	$39.45	1,000 - 1,050	368,413
10/05 - 8/06	Collar	$35.00/$45.60	1,000 - 1,050	368,413

Our hedged volume as of September 30, 2005 was approximately 52% of our estimated production from proved reserves for the balance of the terms of the contracts. Had these contracts been terminated at September 30, 2005, the estimated loss would have been $11.1 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 our existing derivative instruments. Based on the derivative instruments outstanding at September 30, 2005, a 10% increase in the underlying commodity price, would increase the estimated loss associated with the commodity derivative instrument by $2.7 million, net of taxes.

Interest Rate Risk

There have been no significant changes in our interest rate risks since the year ended December 31, 2004. For more information, please read the consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2004.

Item 4. Controls and Procedures

As of the end of the period covered by this quarterly report on Form 10-Q, our chief financial officer and chief executive officer have concluded, based on their evaluation, that our disclosure controls and procedures (as defined in rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended) are effective for ensuring 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 SEC’s rules and forms.

There were no material changes to our system of internal controls over financial reporting or in other factors that have materially affected or are reasonably likely to materially affect those internal controls subsequent to the date of the most recent evaluation by our chief financial officer and chief executive officer.

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PART II. OTHER INFORMATION

Item 6. Exhibits

     (a) The following exhibits are filed with this Form 10-Q:

3.1	Certificate of Incorporation of the Company (incorporated herein by reference to the Company’s Quarterly Report on Form 10-QSB for the quarter ended March 31, 1996).
3.2	Certificate of Amendment to the Company’s Certificate of Incorporation (incorporated herein by reference to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999).
3.3	Amended and Restated Bylaws of the Company (incorporated herein by reference to Exhibit 3.1 to the Company’s Form 8-K filed on November 15, 2004).
31.1	Officer’s certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Officer’s certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Officer’s certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Officer’s certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	SUPERIOR ENERGY SERVICES, INC.
Date: November 8, 2005	By: /s/ Robert S. Taylor
	Robert S. Taylor
	Executive Vice President, Treasurer and
	Chief Financial Officer
	(Principal Financial and Accounting Officer)

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Exhibit Index

3.1	Certificate of Incorporation of the Company (incorporated herein by reference to the Company’s Quarterly Report on Form 10-QSB for the quarter ended March 31, 1996).
3.2	Certificate of Amendment to the Company’s Certificate of Incorporation (incorporated herein by reference to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999).
3.3	Amended and Restated Bylaws of the Company (incorporated herein by reference to Exhibit 3.1 to the Company’s Form 8-K filed on November 15, 2004).
31.1	Officer’s certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Officer’s certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Officer’s certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Officer’s certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.