Superior Energy Services 10-Q 2006 Q3 Quarterly report

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, 2006

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

1105 Peters Road
Harvey, Louisiana	70058
(Address of principal executive offices)	(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. Yesþ Noo

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

Large accelerated filerþ       Accelerated filero       Non-acceleratedo

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yeso Noþ

The number of shares of the registrant’s common stock outstanding on November 1, 2006 was 79,831,733.

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Quarterly Report on Form 10-Q for
the Quarterly Period Ended September 30, 2006

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		29
Item 3. Quantitative and Qualitative Disclosures about Market Risk		37
Item 4. Controls and Procedures		37
PART II OTHER INFORMATION
Item 6. Exhibits		38
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, 2006 and December 31, 2005
(in thousands, except share data)

	9/30/06		12/31/05
	(Unaudited)		(Audited)
ASSETS
Current assets:
Cash and cash equivalents	$	111,882	$	54,457
Accounts receivable, net		269,110		196,365
Current portion of notes receivable		14,558		2,364
Prepaid insurance and other		60,651		51,116
Total current assets		456,201		304,302
Property, plant and equipment, net		661,633		534,962
Goodwill, net		224,807		220,064
Notes receivable		16,524		29,483
Equity-method investments		62,586		953
Other assets, net		12,900		7,486
Total assets	$	1,434,651	$	1,097,250
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	48,862	$	42,035
Accrued expenses		104,639		69,926
Income taxes payable		74,397		11,353
Fair value of commodity derivative instruments		—		10,792
Current portion of decommissioning liabilities		25,067		14,268
Current maturities of long-term debt		810		810
Total current liabilities		253,775		149,184
Deferred income taxes		101,125		97,987
Decommissioning liabilities		96,826		107,641
Long-term debt		311,801		216,596
Other long-term liabilities		3,617		1,468
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, 79,829,021 shares at September 30, 2006, and 79,499,927 shares at December 31, 2005		80		79
Additional paid in capital		434,213		428,507
Accumulated other comprehensive income (loss), net		6,457		(4,916	)
Retained earnings		226,757		100,704
Total stockholders’ equity		667,507		524,374
Total liabilities and stockholders’ equity	$	1,434,651	$	1,097,250

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, 2006 and 2005
(in thousands, except per share data)
(unaudited)

	Three Months						Nine Months
	2006			2005			2006			2005
Oilfield service and rental revenues	$	252,309		$	162,337		$	687,441		$	470,151
Oil and gas revenues		38,208			21,764			87,304			77,197
Total revenues		290,517			184,101			774,745			547,348
Cost of oilfield services and rentals		109,525			90,029			304,066			243,203
Cost of oil and gas sales		19,562			11,368			52,469			35,264
Total cost of services, rentals and sales		129,087			101,397			356,535			278,467
Depreciation, depletion, amortization and accretion		28,831			22,883			77,473			68,860
General and administrative expenses		44,385			37,583			122,124			103,133
Reduction in value of assets		—			3,244			—			3,244
Gain on sale of liftboats		—			—			—			3,269
Income from operations		88,214			18,994			218,613			96,913
Other income (expense):
Interest expense, net		(5,989	)		(5,437	)		(16,389	)		(16,530	)
Interest income		1,255			739			3,477			1,470
Loss on early extinguishment of debt		—			—			(12,596	)		—
Earnings from equity-method investments, net		2,704			558			3,852			1,336
Reduction in value of equity-method investment		—			—			—			(1,250	)
Income before income taxes		86,184			14,854			196,957			81,939
Income taxes		31,026			5,496			70,904			30,318
Net income	$	55,158		$	9,358		$	126,053		$	51,621
Basic earnings per share	$	0.69		$	0.12		$	1.58		$	0.66
Diluted earnings per share	$	0.68		$	0.12		$	1.55		$	0.65
Weighted average common shares used in computing earnings per share:
Basic		79,824			78,707			79,754			77,936
Incremental common shares from stock options		1,480			1,441			1,442			1,467
Incremental common shares from restricted stock units		36			20			36			20
Diluted		81,340			80,168			81,232			79,423

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, 2006 and 2005
(in thousands)
(unaudited)

	2006			2005
Cash flows from operating activities:
Net income	$	126,053		$	51,621
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		77,473			68,860
Deferred income taxes		(1,085	)		(2,748	)
Reduction in value of assets		—			3,244
Stock-based compensation expense		1,776			—
Earnings from equity-method investments		(3,852	)		(1,336	)
Reduction in value of equity-method investment		—			1,250
Write-off of debt acquisition costs		2,817			—
Amortization of debt acquisition costs and note discount		857			672
Gain on sale of liftboats		—			(3,269	)
Changes in operating assets and liabilities, net of acquisitions and dispositions:
Receivables		(75,399	)		(18,330	)
Other — net		(3,125	)		1,119
Accounts payable		7,325			2,924
Accrued expenses		34,318			15,884
Decommissioning liabilities		(2,255	)		(8,199	)
Income taxes		64,142			23,871
Net cash provided by operating activities		229,045			135,563
Cash flows from investing activities:
Payments for capital expenditures		(165,064	)		(92,960	)
Acquisitions of oil and gas properties, net of cash acquired		(46,631	)		3,686
Acquisitions of businesses, net of cash acquired		(9,822	)		(6,435	)
Cash contributed to equity-method investment		(57,781	)		—
Cash proceeds from sale of subsidary, net of cash sold		18,343			—
Cash proceeds from the sale of liftboats, net		—			19,313
Other		(2,542	)		(1,513	)
Net cash used in investing activities		(263,497	)		(77,909	)
Cash flows from financing activities:
Proceeds from long-term debt		295,467			—
Principal payments on long-term debt		(200,405	)		(8,655	)
Payment of debt acquisition costs		(6,516	)		—
Proceeds from exercise of stock options		2,631			17,882
Net cash provided by financing activities		91,177			9,227
Effect of exchange rate changes on cash		700			(771	)
Net increase in cash		57,425			66,110
Cash and cash equivalents at beginning of period		54,457			15,281
Cash and cash equivalents at end of period	$	111,882		$	81,391

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, 2006 and 2005

(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 consolidated financial statements and notes thereto and the Management’s Discussion and Analysis of Financial Condition and Results of Operations for the year ended December 31, 2005 included in Superior Energy Services, Inc.’s Current Report on Form 8-K filed on May 11, 2006 and in the Annual Report on Form 10-K.

The financial information of Superior Energy Services, Inc. and subsidiaries (the Company) for the nine months ended September 30, 2006 and 2005 has not been audited. However, in the opinion of management, all adjustments (which include 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 2006 presentation.

(2)Stock-Based and Long-Term Compensation

The Company maintains various stock incentive plans, including the 2005 Stock Incentive Plan (2005 Incentive Plan), 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 2005 Incentive Plan, the 2002 Incentive Plan, the 1999 Incentive Plan and the 1995 Incentive Plan, the Company may grant incentive stock options, non-qualified stock options, restricted stock, restricted stock units, stock appreciation rights, other stock-based awards or any combination thereof to Eligible Participants for up to 4,000,000 shares, 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 2005 Incentive Plan and 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 Incentive Plan, the 1999 Incentive Plan and the 2002 Incentive Plan were fully-vested by September 30, 2006.

Effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123(R) (FAS No. 123R), “Share-Based Payment (as amended)” which requires that compensation costs relating to share-based payment transactions be recognized in the financial statements. The cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the employee’s requisite service period (generally the vesting period of the equity award). The Company is using the modified prospective application method and, accordingly, financial statement amounts for prior periods presented in this Form 10-Q have not been restated to reflect the fair value method of recognizing compensation costs relating to non-qualified stock options. Prior to January 1, 2006, the Company followed the disclosure-only provisions of Statement of Financial Accounting Standards No. 123 (FAS No. 123), “Accounting for Stock-Based Compensation” using the measurement principles prescribed in Accounting Principles Board’s Opinion No. 25, “Accounting for Stock Issued to Employees.” No stock-based compensation costs were recognized for stock options in net income prior to January 1, 2006, as all options granted had an exercise price equal to the market value of the underlying common stock on the date of the grant. Stock compensation costs from the grant of restricted stock, restricted stock units, and performance share units were expensed as incurred.

6

Stock Options

The Company has granted non-qualified stock options under its stock incentive plans. The options generally vest in equal installments over three years and expire in ten years. Non-vested options are generally forfeited upon termination of employment. On February 23, 2006, the Company granted 212,600 non-qualified stock options from its 2005 Incentive Plan under these same terms.

Beginning January 1, 2006, the Company began recognizing compensation expense for stock option grants based on the fair value at the date of grant using the Black-Scholes-Merton option pricing model. With the adoption of FAS No. 123R, the Company has contracted a third party to assist in the valuation of option grants. The Company uses historical data, among other factors, to estimate the expected price volatility, the expected option life and the expected forfeiture rate. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant for the expected life of the option. The following table presents the fair value of stock option grants made during the nine months ended September 30, 2006 and 2005 and the related assumptions used to calculate the fair value (no stock option grants were made during the three months ended September 30, 2006 or 2005):

	Nine Months Ended
	September 30,			September 30,
	2006			2005
	Actual			Pro Forma
Weighted-average fair value of grants	$	11.58		$	7.47
Black-Scholes-Merton Assumptions:
Risk free interest rate		4.57	%		3.85	%
Expected life (years)		5.1			5.7
Volatility		45.42	%		38.91	%
Dividend yield		—			—

The Company’s compensation expense related to stock options for the nine months ended September 30, 2006 was approximately $0.6 million, which is reflected in general and administrative expenses. No compensation expense related to options was recorded during the nine months ended September 30, 2005.

The pro forma data presented below show the effects of stock option costs had they been expensed in prior periods (amounts are in thousands, except per share amounts):

7

	Three Months			Nine Months
	Ended			Ended
	September 30,			September 30,
	2005			2005
Net income, as reported	$	9,358		$	51,621
Stock-based employee compensation expense, net of tax		(2,057	)		(2,363	)
Pro forma net income	$	7,301		$	49,258
Basic earnings per share:
Earnings, as reported	$	0.12		$	0.66
Stock-based employee compensation expense, net of tax		(0.03	)		(0.03	)
Pro forma earnings per share	$	0.09		$	0.63
Diluted earnings per share:
Earnings, as reported	$	0.12		$	0.65
Stock-based employee compensation expense, net of tax		(0.03	)		(0.03	)
Pro forma earnings per share	$	0.09		$	0.62

The following table summarizes stock option activity for the nine months ended September 30, 2006:

						Weighted
						Average		Aggregate
				Weighted		Remaining		Intrinsic
	Number of			Average		Contractual		Value (in
	Options			Option Price		Term (in years)		thousands)
Outstanding at December 31, 2005		3,893,633		$	11.44
Granted		212,600		$	24.99
Exercised		(227,651	)	$	11.56
Forfeited		(18,917	)	$	16.85
Outstanding at September 30, 2006		3,859,665		$	12.15		7.1	$	54,465
Exercisable at September 30, 2006		3,647,065		$	11.40		7.0	$	54,195
Options expected to vest		212,600		$	11.58		9.4	$	270

The aggregate intrinsic value in the table above represents the total pre-tax intrinsic value (the difference between the Company’s closing stock price on September 30, 2006 and the option price, multiplied by the number of in-the-money options) that would have been received by the option holders if all the options had been exercised on September 30, 2006. The Company expects all of its remaining non-vested options to vest as they are primarily held by its officers and senior managers.

The total intrinsic value of options exercised during the nine months ended September 30, 2006 (the difference between the stock price upon exercise and the option price) was approximately $3.6 million. The Company received approximately $2.6 million during the nine months ended September 30, 2006 from employee stock option exercises. The Company expects to reduce its future tax payments by approximately $1.3 million as the result of the intrinsic value of options exercised during the nine months ended September 30, 2006. In accordance with Statement 123R, the Company will report the excess tax benefits from the exercise of stock options as financing cash flows when income tax payments are made during the fourth quarter of 2006.

8

The following table summarizes non-vested stock option activity for the nine months ended September 30, 2006:

				Weighted
				Average
	Number of			Grant-Date
	Options			Fair Value
Non-vested at December 31, 2005		133,912		$	3.63
Granted		212,600		$	11.58
Vested		(133,245	)	$	3.64
Forfeited		(667	)	$	3.62
Non-vested at September 30, 2006		212,600		$	11.58

As of September 30, 2006, there was approximately $2.0 million of unrecognized compensation expense related to non-vested stock options outstanding. The Company expects to recognize approximately $0.2 million, $0.8 million, $0.8 million and $0.2 million of compensation expense during the remainder of 2006, the years 2007, 2008 and 2009, respectively, for these non-vested stock options outstanding.

Restricted Stock

During the nine months ended September 30, 2006, the Company granted 104,643 shares of restricted stock to its employees. These shares of restricted stock vest in equal annual installments over three years. Non-vested shares are generally forfeited upon the termination of employment. 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. Compensation expense associated with shares of restricted stock is measured based on the grant-date fair value of our common stock and is recognized on a straight-line basis over the vesting period. The Company’s compensation expense related to shares of restricted stock outstanding for the nine months ended September 30, 2006 was approximately $0.6 million, which is reflected in general and administrative expenses.

A summary of the status of the shares of restricted stock for the nine months ended September 30, 2006 is presented in the table below:

				Weighted
	Number of			Average Grant
	Shares			Date Fair Value
Non-vested at December 31, 2005		24,000		$	22.24
Granted		104,643		$	25.02
Vested		(9,000	)	$	22.55
Forfeited		(3,200	)	$	24.99
Non-vested at September 30, 2006		116,443		$	24.64

As of September 30, 2006, there was approximately $2.2 million of unrecognized compensation expense related to non-vested restricted stock shares. The Company expects to recognize approximately $0.3 million, $1.0 million, $0.8 million and $0.1 million during the remainder of 2006, the years 2007, 2008 and 2009, respectively, for these shares of non-vested restricted stock.

9

Restricted Stock Units

In May 2006, the Company’s stockholders approved the Amended and Restated 2004 Directors Restricted Stock Units Plan. The amended plan provides that each non-employee director is granted a number of restricted stock units having an aggregate value of $100,000, with the exact number of units determined by dividing $100,000 by the fair market value of the Company’s common stock on the day of the annual stockholders’ meeting. In addition, upon the initial election or appointment of any non-employee director, other than at an annual stockholders’ meeting, such person will receive a 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, 36,137 restricted stock units are outstanding at September 30, 2006. The Company’s expense related to restricted stock units for the nine months ended September 30, 2006 and 2005 was approximately $0.7 million and $0.1 million, respectively, which is reflected in general and administrative expenses.

A summary of the activity of restricted stock units for the nine months ended September 30, 2006 is presented in the table below:

	Number of		Weighted
	Restricted		Average Grant
	Stock Units		Date Fair Value
Outstanding at December 31, 2005		19,998	$	12.38
Granted		16,139	$	30.98
Outstanding at September 30, 2006		36,137	$	20.69

Performance Share Units

The Company awards performance share units (PSUs) to its employees as part of the Company’s long-term incentive program. There is a 3-year performance period associated with each PSU grant date. The two performance measures applicable to all participants are the Company’s return on invested capital and total shareholder return relative to those of the Company’s pre-defined “peer group.” The PSUs provide for settlement in cash or up to 50% in equivalent value in Company common stock, if the participant has met specified continued service requirements. At September 30, 2006 there were 64,462 PSUs outstanding (31,250 and 33,212 related to the 3-year performance periods ending December 31, 2007 and 2008, respectively). The Company’s compensation expense related to all outstanding PSUs for the nine months ended September 30, 2006 and 2005 was approximately $1.7 million and $0.5 million, respectively, which is reflected in general and administrative expenses. At September 30, 2006, the Company has recorded a liability of approximately $2.8 million for all outstanding PSUs which is reflected in accrued expenses.

(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 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 that would have a dilutive effect on earnings per share and the conversion of restricted stock units into common stock using the treasury stock method.

(4)Acquisitions and Dispositions

In July 2006, Coldren Resources LP (Coldren Resources) completed the acquisition from Noble Energy, Inc. (Noble) of substantially all of Noble’s offshore Gulf of Mexico shallow water oil and gas properties. SPN Resources, LLC, a wholly-owned subsidiary of the Company (SPN Resources), acquired a 40% interest in Coldren

10

Resources for an initial cash investment of $57.7 million. The Company’s investment in Coldren Resources is accounted for under the equity-method of accounting. Amounts included in the pro forma information below do not include general and administrative expenses associated with the oil and gas properties acquired from Noble.

In the second quarter of 2006, the Company acquired two businesses for an aggregate purchase price of approximately $9.8 million in cash consideration in order to expand the housing units offered by its rental tools segment into Wyoming and expand the snubbing services offered by its well intervention segment in Australia. These acquisitions have been accounted for as purchases, and the acquired assets and liabilities have been valued at their estimated fair value. The results of operations have been included from the acquisition date.

In April 2006, SPN Resources acquired additional oil and gas properties through the acquisition of five offshore Gulf of Mexico leases. Under the terms of the transaction, the Company acquired the properties and assumed the related decommissioning liabilities. The Company paid cash in the amount of $46.6 million and preliminarily recorded decommissioning liabilities of approximately $3.7 million and oil and gas producing assets of approximately $50.3 million.

In February 2006, the Company sold its subsidiary, Environmental Treatment Team, L.L.C. (ETT), for approximately $18.7 million in cash. The Company reduced the net asset value of ETT by $3.8 million in 2005 to its approximate sales price. For the nine months ended September 30, 2006 and 2005, revenue from ETT was approximately $4.6 million and $21.1 million, respectively, and operating loss was approximately $3,000 and $687,000, respectively.

In 2005, the Company acquired a business for a purchase price of approximately $1.3 million in cash consideration in order to geographically expand the snubbing services offered by its well intervention segment. The results of operations have been included from the acquisition date.

Also in 2005, SPN Resources acquired additional oil and gas properties 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 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 following unaudited pro forma information for the three and nine months ended September 30, 2006 and 2005 presents a summary of the consolidated results of operations as if the business acquisitions and dispositions described above had occurred on January 1, 2005, with pro forma adjustments to give effect to depreciation, depletion and certain other adjustments, together with related income tax effects (in thousands, except per share amounts):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2006		2005		2006		2005
Revenues	$	290,517	$	183,604	$	775,571	$	542,985
Net income	$	56,827	$	20,501	$	144,804	$	78,337
Basic earnings per share	$	0.71	$	0.26	$	1.82	$	1.01
Diluted earnings per share	$	0.70	$	0.26	$	1.78	$	0.99

The above pro forma information is not necessarily indicative of the results of operations that would have been achieved had the acquisitions and dispositions been effected on January 1, 2005.

Several of the Company’s prior business acquisitions have required future payments based upon a multiple of the acquired business’ future earnings before interest, income taxes, depreciation and amortization. As of September 30, 2006, the maximum additional contingent consideration payable was approximately $2.4 million, and will be

11

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.

(5)Merger Agreement

In September 2006, the Company entered into a definitive merger agreement to acquire Warrior Energy Services Corporation (Warrior) for a total estimated purchase price of approximately $319.0 million. The total consideration is composed of cash payments of approximately $175.2 million ($14.50 per share of outstanding Warrior common stock), $133.8 million in equity (approximately 5.3 million shares of Superior common stock, at an exchange ratio of 0.452 of Superior common stock for each share of Warrior common stock, multiplied by the Superior’s share price of $25.39, the average closing market price per share for the five trading day period beginning two trading days before the merger announcement date of September 25, 2006), and approximately $10 million of estimated direct transaction costs. Warrior is a natural gas and oil well services company that provides wireline and well intervention services to exploration and production companies. Warrior’s operations are concentrated in the major onshore and offshore natural gas and oil producing areas of the U.S. The transaction is subject to customary closing conditions, and is expected to close in the middle of December 2006.

In connection with the Warrior acquisition, the Company has obtained a commitment for a seven year $200 million secured term loan to fund the cash portion of the merger consideration and refinance a portion of Warrior’s existing debt. The term loan is expected to bear interest, at the Company’s election, at the prime rate plus 50 basis points or LIBOR plus up to 225 basis points and will be payable in quarterly installments of 0.25% of the initial term amount for the first six years with the balance due in the seventh year.

(6)Segment Information

Business Segments

Effective as of January 1, 2006, 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 has four reportable segments: well intervention, rental tools, marine, and oil and gas. The well intervention segment provides: (1) production related services used to enhance, extend and maintain oil and gas production, (2) well plug and abandonment services, and (3) other oilfield services used to support drilling and production operations. Production related services include mechanical wireline, hydraulic workover and snubbing, well control, coiled tubing, case-hole logging, pumping and stimulation and wellbore evaluation services. 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. Oil and gas eliminations represent products and services provided to the oil and gas segment by the Company’s three other segments.

Summarized financial information concerning the Company’s segments for the three and nine months ended September 30, 2006 and 2005 is shown in the following tables (in thousands):

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Three Months Ended September 30, 2006

									Oil & Gas
	Well		Rental						Eliminations			Consolidated
	Intervention		Tools		Marine		Oil & Gas		& Unallocated			Total
Revenues	$	122,205	$	98,262	$	36,013	$	38,208	$	(4,171	)	$	290,517
Cost of services, rentals and sales		68,438		30,786		14,472		19,562		(4,171	)		129,087
Depreciation, depletion, amortization and accretion		4,511		13,600		2,142		8,578		—			28,831
General and administrative expense		20,428		18,776		3,231		1,950		—			44,385
Income from operations		28,828		35,100		16,168		8,118		—			88,214
Interest expense, net		—		—		—		—		(5,989	)		(5,989	)
Interest income		—		—		—		286		969			1,255
Loss on early extinguishment of debt		—		—		—		—		—			—
Earnings in equity method investments		—		—		—		2,704		—			2,704
Income before income taxes	$	28,828	$	35,100	$	16,168	$	11,108	$	(5,020	)	$	86,184

Three Months Ended September 30, 2005

											Oil & Gas
	Well			Rental							Eliminations			Consolidated
	Intervention			Tools		Marine		Oil & Gas			& Unallocated			Total
Revenues	$	85,848		$	61,686	$	18,467	$	21,764		$	(3,664	)	$	184,101
Cost of services, rentals and sales		59,862			21,992		11,839		11,368			(3,664	)		101,397
Depreciation, depletion, amortization and accretion		4,589			10,970		1,987		5,337			—			22,883
General and administrative expense		19,801			13,913		2,497		1,372			—			37,583
Income from operations		1,596			14,811		2,144		3,687			—			22,238
Interest expense, net		—			—		—		—			(5,437	)		(5,437	)
Interest income		—			—		—		294			445			739
Earnings in equity method investments, net		—			558		—		—			—			558
Reduction in value of investment		(1,100	)		—		—		(2,144	)		—			(3,244	)
Income before income taxes	$	496		$	15,369	$	2,144	$	1,837		$	(4,992	)	$	14,854

13

Nine Months Ended September 30, 2006

									Oil & Gas
	Well		Rental						Eliminations			Consolidated
	Intervention		Tools		Marine		Oil & Gas		& Unallocated			Total
Revenues	$	335,953	$	262,629	$	100,171	$	87,304	$	(11,312	)	$	774,745
Cost of services, rentals and sales		191,793		83,307		40,278		52,469		(11,312	)		356,535
Depreciation, depletion, amortization and accretion		13,375		37,795		6,427		19,876		—			77,473
General and administrative expense		56,566		50,525		8,816		6,217		—			122,124
Income from operations		74,219		91,002		44,650		8,742		—			218,613
Interest expense, net		—		—		—		—		(16,389	)		(16,389	)
Interest income		—		—		—		888		2,589			3,477
Loss on early extinguishment of debt		—		—		—		—		(12,596	)		(12,596	)
Earnings in equity method investments		—		—		—		3,852		—			3,852
Income before income taxes	$	74,219	$	91,002	$	44,650	$	13,482	$	(26,396	)	$	196,957

Nine Months Ended September 30, 2005

												Oil & Gas
	Well			Rental								Eliminations			Consolidated
	Intervention			Tools			Marine		Oil & Gas			& Unallocated			Total
Revenues	$	250,983		$	175,435		$	56,550	$	77,197		$	(12,817	)	$	547,348
Cost of services, rentals and sales		161,382			58,403			36,235		35,264			(12,817	)		278,467
Depreciation, depletion, amortization and accretion		13,693			31,340			6,107		17,720			—			68,860
General and administrative expense		52,452			39,534			6,712		4,435			—			103,133
Gain on sale of liftboats		—			—			3,269		—			—			3,269
Income from operations		23,456			46,158			10,765		19,778			—			100,157
Interest expense, net		—			—			—		—			(16,530	)		(16,530	)
Interest income		—			—			—		849			621			1,470
Earnings in equity method investments, net		—			1,336			—		—			—			1,336
Reduction in value of investment		(1,100	)		(1,250	)		—		(2,144	)		—			(4,494	)
Income before income taxes	$	22,356		$	46,244		$	10,765	$	18,483		$	(15,909	)	$	81,939

Identifiable Assets

	Well		Rental								Consolidated
	Intervention		Tools		Marine		Oil & Gas		Unallocated		Total
September 30, 2006	$	407,699	$	504,403	$	193,765	$	315,912	$	12,872	$	1,434,651
December 31, 2005	$	332,996	$	405,527	$	203,718	$	147,667	$	7,342	$	1,097,250

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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):

	Three Months Ended September 30,				Nine Months Ended September 30,
Revenues:	2006		2005		2006		2005
United States	$	248,822	$	159,858	$	663,354	$	479,485
Other Countries		41,695		24,243		111,391		67,863
Total	$	290,517	$	184,101	$	774,745	$	547,348

	September 30,		December 31,
Long-Lived Assets:	2006		2005
United States	$	572,754	$	492,602
Other Countries		88,879		42,360
Total	$	661,633	$	534,962

(7)Construction Contract

In July 2006, the Company contracted to construct a derrick barge that will be sold to a third party for approximately $54 million. The contract to construct the derrick barge to the customer’s specifications is recorded on the percentage-of-completion method using a milestone-based measure focused on engineering estimates and manufacturing progress. This method is used because the Company believes it is the most meaningful measure of the extent of progress toward completion. This methodology requires the Company to make estimates regarding the progress against the project schedule and estimated completion date, both of which impact the amount of revenue and gross margin the Company recognizes in each reporting period. Contract costs primarily include sub-contract and program management costs. Provisions for anticipated losses will be recorded in full when such losses become evident. For the three months ended September 30, 2006, the Company recognized approximately $430,000 of revenues and approximately $154,000 of gross profit on this contract. Included in accrued expenses at September 30, 2006 is approximately $5.2 million of billings in excess of costs.

(8)Equity-Method Investments

Investments in entities that are not controlled by the Company, but where the Company has the ability to exercise influence over the operations are accounted for using the equity-method. The Company’s share of the income or losses of these entities is reflected as earnings in equity-method investments on its Consolidated Statements of Operations.

In May 2006, SPN Resources acquired a 40% interest in Coldren Resources. In July 2006, Coldren Resources completed its acquisition of the oil and gas properties from Noble. The Company made total cash contributions for its equity-method investment of approximately $57.7 million through September 30, 2006. The Company’s equity-method investment balance in Coldren Resources is approximately $61.6 million at September 30, 2006, and its earnings from the equity-method investments in Coldren Resources is approximately $2.7 million and $3.8 million for the three and nine months ended September 30, 2006, respectively. The Company also has a receivable from Coldren Resources of approximately $1.0 million at September 30, 2006.

Summarized balance sheet and statement of operations information for Coldren Resources is presented below. (Amounts in thousands.)

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	September 30,
Balance Sheet	2006
Current assets	$	129,453
Property, plant and equipment, net		535,057
Other assets		12,667
Total assets	$	677,177
Current liabilities	$	13,790
Decommissioning and other long-term liabilities		93,051
Long-term debt		422,517
Partners’ equity		147,819
Total liabilities and partners’ equity	$	677,177

	Nine Months
	Ended
	September 30,
Income Statement	2006
Revenues	$	61,458
Lease operating expenses		(17,615	)
Depreciation, depletion, amortization and accretion		(35,874	)
General and administrative expenses		(2,837	)
Interest expense		(9,915	)
Interest income		688
Gain on derivatives		13,679
Net income	$	9,584

Also included in equity-method investments is a 50% ownership in a company that owns an airplane of approximately $1.0 million at September 30, 2006. Earnings from the equity-method investment in this company were not material for the three and nine months ended September 30, 2006 or 2005.

(9)Debt

The Company has a bank credit facility consisting of a $150 million revolving credit facility, with an option to increase it to $250 million. Any amounts outstanding under the revolving credit facility are due on October 31, 2008. At September 30, 2006, the Company had no amounts outstanding under the bank credit facility, but it had approximately $21.2 million of letters of credit outstanding, which reduces the borrowing availability under this 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, create liens, incur additional indebtedness or assume additional decommissioning liabilities. The Company obtained consent from the required lenders to increase the limitation on the amount of capital expenditures for the fiscal year ending December 31, 2006. As a result, the Company was in compliance with all such covenants.

The Company has $17 million outstanding at September 30, 2006, 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

16

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. The Company was in compliance with all such covenants. This long-term financing ranks equally with the bank credit facility.

In the second quarter of 2006, the Company completed a tender offer for approximately 97.6% of its $200 million outstanding of 8 7/8% unsecured senior notes due 2011. The cash consideration for the tender offer was $1,045.63 per $1,000 in aggregate principal amount of senior notes tendered. In conjunction with the tender offer, the Company also received consents to amend the indenture pursuant to which the senior notes were issued to eliminate from the indenture substantially all of the restrictive covenants and certain events of default. After the tender offer was completed, the Company redeemed the remaining outstanding senior notes in accordance with the indenture at the redemption price of $1,044.38 per $1,000 of the principal amount redeemed. The Company recognized a loss on the early extinguishment of debt of approximately $12.6 million, which included the tender premiums, redemption premiums, fees and expenses and the write-off of the remaining unamortized debt acquisition costs associated with these notes.

In May 2006, the Company issued $300 million of 6 7/8% unsecured senior notes due 2014. The Company used the net proceeds to refinance the 8 7/8% senior notes due 2011 and related tender and redemption premiums, fees and related expenses, and to fund the equity investment in Coldren Resources. The indenture governing the notes requires semi-annual interest payments, on every June 1^st and December 1^st through the maturity date of June 1, 2014. The indenture contains certain covenants that, among other things, restrict the Company from incurring additional debt, repurchasing capital stock, paying dividends or making other distributions, incurring liens, selling assets or entering into certain mergers or acquisitions. The Company was in compliance with all such covenants.

(10)Hedging Activities

The Company entered into hedging transactions in 2004 that expired on August 31, 2006 with major financial institutions to secure a range of commodity prices for a portion of its future oil production and to reduce its exposure to oil price fluctuations. 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 used financially-settled crude oil swaps and zero-cost collars that provided floor and ceiling prices with varying upside price participation. The Company’s swaps and zero-cost collars were designated and accounted for as cash flow hedges. The Company had not hedged any of its natural gas production.

With a financially-settled swap, the counterparty was required to make a payment to the Company if the settlement price for any settlement period was below the hedged price for the transaction, and the Company was required to make a payment to the counterparty if the settlement price for any settlement period was above the hedged price for the transaction. With a zero-cost collar, the counterparty was required to make a payment to the Company if the settlement price for any settlement period was below the floor price of the collar, and the Company was required to make a payment to the counterparty if the settlement price for any settlement period was above the cap price for the collar. The Company recognized the fair value of all derivative instruments as assets or liabilities on the balance sheet. Changes in the fair value of cash flow hedges were recognized, to the extent the hedge was effective, in other comprehensive income until the hedged item was settled and recorded in revenue. For the nine months ended September 30, 2006, hedging settlement payments reduced oil revenues by approximately $13.8 million, and no gains or losses were recognized due to hedge ineffectiveness.

(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

17

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 the related facilities and equipment, and site restoration.

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 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 and related costs of services 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 total 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 expenditures 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 Company revised its estimates for the timing of these expenditures during the nine months ended September 30, 2006, which caused a reduction in the decommissioning liability of approximately $4.9 million. The following table summarizes the activity for the Company’s decommissioning liabilities for the nine months ended September 30, 2006 and 2005 (amounts in thousands):

	Nine Months Ended
	September 30,
	2006			2005
Total decommissioning liabilities at December 31, 2005 and 2004, respectively	$	121,909		$	114,018
Liabilities acquired and incurred		3,554			11,494
Liabilities settled		(2,255	)		(8,199	)
Accretion		3,609			3,290
Revision in estimated liabilities		(4,924	)		(2,873	)
Total decommissioning liabilities at September 30, 2006 and 2005, respectively		121,893			117,730
Current portion of decommissioning liabilities at September 30, 2006 and 2005, respectively		25,067			10,084
Long-term portion of decommissioning liabilities at September 30, 2006 and 2005, respectively	$	96,826		$	107,646

(12)Notes Receivable

Notes receivable consist primarily of contractual obligations of sellers of oil and gas properties to reimburse the Company a specified amount following the abandonment of acquired properties. The Company invoices the seller specified amounts following the performance of decommissioning operations (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)Prepaid Insurance and Other

Prepaid insurance and other includes approximately $20.4 million and $23.9 million in insurance receivables at September 30, 2006 and December 31, 2005, respectively. The balances are primarily due to property and casualty insurance claims caused by the impact of Hurricanes Katrina and Rita on our oil and gas properties, as well as our

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buildings and equipment. 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.

(14)Other Comprehensive Income

The following tables reconcile the change in accumulated other comprehensive income (loss) for the three and nine months ended September 30, 2006 and 2005 (amounts in thousands):

	Three Months Ended
	September 30,
	2006		2005
Accumulated other comprehensive income (loss), June 30, 2006 and 2005, respectively	$	1,104	$	(6,865	)
Other comprehensive income (loss):
Other comprehensive income (loss), net of tax
Hedging activities:
Adjustment for settled contracts, net of tax of $2,065 in 2006 and $1,294 in 2005		3,516		2,203
Changes in fair value of outstanding hedging positions, net of tax of $28 in 2006 and ($2,232) in 2005		48		(3,800	)
Foreign currency translation adjustment		1,789		(891	)
Total other comprehensive income (loss)		5,353		(2,488	)
Accumulated other comprehensive income (loss), September 30, 2006 and 2005, respectively	$	6,457	$	(9,353	)

	Nine Months Ended
	September 30,
	2006			2005
Accumulated other comprehensive (loss) income, December 31, 2005 and 2004, respectively	$	(4,916	)	$	2,884
Other comprehensive income (loss):
Other comprehensive income (loss), net of tax
Hedging activities:
Adjustment for settled contracts, net of tax of $5,124 in 2006 and $2,397 in 2005		8,726			4,080
Changes in fair value of outstanding hedging positions, net of tax of ($1,131) in 2006 and ($7,929) in 2005		(1,927	)		(13,499	)
Foreign currency translation adjustment		4,574			(2,818	)
Total other comprehensive income (loss)		11,373			(12,237	)
Accumulated other comprehensive income (loss), September 30, 2006 and 2005, respectively	$	6,457		$	(9,353	)

(15)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.

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(16)Accounting Pronouncements

In February 2006, the Financial Accounting Standards Board issued its Statement of Financial Accounting Standards No. 155 (FAS No. 155), “Accounting for Certain Hybrid Financial Instruments – an amendment of FASB Statements No. 133 and 140.” FAS No. 155 simplifies accounting for certain hybrid financial instruments by permitting fair value remeasurement for any hybrid instrument that contains an embedded derivative that otherwise would require bifurcation and eliminates a restriction on the passive derivative instruments that a qualifying special-purpose entity may hold. FAS No. 155 is effective for all financial instruments acquired, issued or subject to a remeasurement (new basis) event occurring after the beginning of an entity’s first fiscal year that begins after September 15, 2006. The Company does not expect the adoption of FAS No. 155 to have any impact on its results of operations or financial position.

In March 2006, the Financial Accounting Standards Board issued its Statement of Financial Accounting Standards No. 156 (FAS No. 156), “Accounting for Servicing of Financial Assets – an amendment of FASB Statement No. 140.” FAS No. 156 establishes, among other things, the accounting for all separately recognized servicing assets and servicing liabilities by requiring that all separately recognized servicing assets and servicing liabilities be initially measured at fair value, if practicable. FAS No. 156 is effective as of the beginning of an entity’s first fiscal year that begins after September 15, 2006. The adoption of FAS No. 156 will have no impact on the Company’s results of operations or financial position.

In July 2006, the Financial Accounting Standards Board issued FASB Interpretation No. 48 (FIN No. 48), “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109.” FIN No. 48 provides guidance on measurement and recognition in accounting for income tax uncertainties and also requires expanded financial statement disclosure. This interpretation is effective for fiscal years beginning after December 15, 2006. The Company is currently evaluating the impact, if any, that FIN No. 48 will have on its results of operations and financial position.

In September 2006, the Financial Accounting Standards Board issued its Statement of Financial Accounting Standards No. 157 (FAS No. 157), “Fair Value Measurements”. FAS No. 157 establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. FAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company is currently evaluating the impact that FAS No. 157 will have on its results of operations and financial position.

(17)Financial Information Related to Guarantor Subsidiaries

In May 2006, SESI, L.L.C. (Issuer), a wholly-owned subsidiary of Superior Energy Services, Inc. (Parent), issued $300 million of 6 7/8% Senior Notes due 2014 at 98.489%. The Parent, along with substantially all of its subsidiaries, fully and unconditionally guaranteed the Senior Notes and such guarantees are joint and several. All of the guarantor subsidiaries are wholly-owned subsidiaries of the Issuer. Income taxes are paid by the Parent through a consolidated tax return and are accounted for by the Parent. The following tables present the condensed consolidating financial statements as of September 30, 2006 and December 31, 2005 and for the three and nine months ended September 30, 2006 and 2005.

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SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidating Balance Sheets
September 30, 2006
(in thousands)
(unaudited)

									Non-
							Guarantor		Guarantor
	Parent			Issuer			Subsidiaries		Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	78,496		$	19,389	$	13,997	$	—		$	111,882
Accounts receivable, net		—			2,646			244,579		35,440		(13,555	)		269,110
Current portion of notes receivable		—			—			14,558		—		—			14,558
Prepaid insurance and other		18			7,362			50,528		2,743		—			60,651
Total current assets		18			88,504			329,054		52,180		(13,555	)		456,201
Property, plant and equipment, net		—			—			600,885		60,748		—			661,633
Goodwill, net		—			—			199,267		25,540		—			224,807
Notes receivable		—			—			16,524		—		—			16,524
Equity-method investments		124,271			190,443			61,615		971		(314,714	)		62,586
Other assets, net		—			12,444			340		116		—			12,900
Total assets	$	124,289		$	291,391		$	1,207,685	$	139,555	$	(328,269	)	$	1,434,651
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	—		$	341		$	44,233	$	17,843	$	(13,555	)	$	48,862
Accrued expenses		438			26,596			68,740		8,865		—			104,639
Income taxes payable		72,358			—			—		2,039		—			74,397
Current portion of decommissioning liabilities		—			—			25,067		—		—			25,067
Current maturities of long-term debt		—			—			—		810		—			810
Total current liabilities		72,796			26,937			138,040		29,557		(13,555	)		253,775
Deferred income taxes		97,455			—			—		3,670		—			101,125
Decommissioning liabilities		—			—			96,826		—		—			96,826
Long-term debt		—			295,610			—		16,191		—			311,801
Intercompany payables/(receivables)		(338,156	)		35,214			459,503		26,529		(183,090	)		—
Other long-term liabilities		—			3,617			—		—		—			3,617
Stockholders’ equity:
Preferred stock of $.01 par value		—			—			—		—		—			—
Common stock of $.001 par value		80			—			—		101		(101	)		80
Additional paid in capital		434,213			127,173			—		4,350		(131,523	)		434,213
Accumulated other comprehensive income, net		—			—			—		6,457		—			6,457
Retained earnings (deficit)		(142,099	)		(197,160	)		513,316		52,700		—			226,757
Total stockholders’ equity		292,194			(69,987	)		513,316		63,608		(131,624	)		667,507
Total liabilities and stockholders’ equity	$	124,289		$	291,391		$	1,207,685	$	139,555	$	(328,269	)	$	1,434,651

21

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidating Balance Sheets
December 31, 2005
(in thousands)
(audited)

										Non-
							Guarantor			Guarantor
	Parent			Issuer			Subsidiaries			Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	21,414		$	19,421		$	13,622	$	—		$	54,457
Accounts receivable, net		—			3,748			180,670			23,332		(11,385	)		196,365
Current portion of notes receivable		—			—			2,364			—		—			2,364
Prepaid insurance and other		—			3,039			46,237			1,840		—			51,116
Total current assets		—			28,201			248,692			38,794		(11,385	)		304,302
Property, plant and equipment, net		—			—			481,265			53,697		—			534,962
Goodwill, net		—			—			196,696			23,368		—			220,064
Notes receivable		—			—			29,483			—		—			29,483
Equity-method investments		124,271			203,083			—			953		(327,354	)		953
Other assets, net		—			6,390			553			543		—			7,486
Total assets	$	124,271		$	237,674		$	956,689		$	117,355	$	(338,739	)	$	1,097,250
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	—		$	821		$	34,790		$	17,809	$	(11,385	)	$	42,035
Accrued expenses		269			17,300			46,025			6,332		—			69,926
Income taxes payable		9,917			—			—			1,436		—			11,353
Fair value of commodity derivative instruments		—			—			10,792			—		—			10,792
Current portion of decommissioning liabilities		—			—			14,268			��		—			14,268
Current maturities of long-term debt		—			—			—			810		—			810
Total current liabilities		10,186			18,121			105,875			26,387		(11,385	)		149,184
Deferred income taxes		95,196			—			—			2,791		—			97,987
Decommissioning liabilities		—			—			107,641			—		—			107,641
Long-term debt		—			200,000			—			16,596		—			216,596
Intercompany payables/(receivables)		(332,937	)		31,751			467,362			29,554		(195,730	)		—
Other long-term liabilities		—			1,458			10			—		—			1,468
Stockholders’ equity:
Preferred stock of $.01 par value		—			—			—			—		—			—
Common stock of $.001 par value		79			—			—			101		(101	)		79
Additional paid in capital		428,507			127,173			—			4,350		(131,523	)		428,507
Accumulated other comprehensive income (loss), net		—			—			(6,799	)		1,883		—			(4,916	)
Retained earnings (deficit)		(76,760	)		(140,829	)		282,600			35,693		—			100,704
Total stockholders’ equity		351,826			(13,656	)		275,801			42,027		(131,624	)		524,374
Total liabilities and stockholders’ equity	$	124,271		$	237,674		$	956,689		$	117,355	$	(338,739	)	$	1,097,250

22

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidating Statements of Operations
Three Months Ended September 30, 2006
(in thousands)
(unaudited)

										Non-
							Guarantor			Guarantor
	Parent			Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Oilfield service and rental revenues	$	—		$	—		$	224,102		$	35,186		$	(6,979	)	$	252,309
Oil and gas revenues		—			—			38,208			—			—			38,208
Total revenues		—			—			262,310			35,186			(6,979	)		290,517
Cost of oilfield services and rentals		—			—			99,044			17,460			(6,979	)		109,525
Cost of oil and gas sales		—			—			19,562			—			—			19,562
Total cost of services, rentals and sales		—			—			118,606			17,460			(6,979	)		129,087
Depreciation, depletion, amortization and accretion		—			—			26,031			2,800			—			28,831
General and administrative expenses		118			13,312			27,408			3,547			—			44,385
Income from operations		(118	)		(13,312	)		90,265			11,379			—			88,214
Other income (expense):
Interest expense, net		—			(5,537	)		(178	)		(274	)		—			(5,989	)
Interest income		—			768			409			78			—			1,255
Earnings in equity-method investments, net		—			—			2,701			3			—			2,704
Income before income taxes		(118	)		(18,081	)		93,197			11,186			—			86,184
Income taxes		28,240			—			—			2,786			—			31,026
Net income (loss)	$	(28,358	)	$	(18,081	)	$	93,197		$	8,400		$	—		$	55,158

23

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidating Statements of Operations
Three Months Ended September 30, 2005
(in thousands)
(unaudited)

										Non-
							Guarantor			Guarantor
	Parent			Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Oilfield service and rental revenues	$	—		$	—		$	147,734		$	22,120		$	(7,517	)	$	162,337
Oil and gas revenues		—			—			21,764			—			—			21,764
Total revenues		—			—			169,498			22,120			(7,517	)		184,101
Cost of oilfield services and rentals		—			—			86,207			11,339			(7,517	)		90,029
Cost of oil and gas sales		—			—			11,368			—			—			11,368
Total cost of services, rentals and sales		—			—			97,575			11,339			(7,517	)		101,397
Depreciation, depletion, amortization and accretion		—			—			20,864			2,019			—			22,883
General and administrative expenses		105			8,173			26,923			2,382			—			37,583
Reduction in value of assets		—			—			3,244			—			—			3,244
Income from operations		(105	)		(8,173	)		20,892			6,380			—			18,994
Other income (expense):
Interest expense, net		—			(5,132	)		(1	)		(304	)		—			(5,437	)
Interest income		—			383			303			53			—			739
Earnings in equity-method investments, net		—			—			—			558			—			558
Income before income taxes		(105	)		(12,922	)		21,194			6,687			—			14,854
Income taxes		3,508			—			—			1,988			—			5,496
Net income (loss)	$	(3,613	)	$	(12,922	)	$	21,194		$	4,699		$	—		$	9,358

24

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidating Statements of Operations
Nine Months Ended September 30, 2006
(in thousands)
(unaudited)

							Guarantor			Non-Guarantor
	Parent			Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Oilfield service and rental revenues	$	—		$	—		$	620,252		$	85,075		$	(17,886	)	$	687,441
Oil and gas revenues		—			—			87,304			—			—			87,304
Total revenues		—			—			707,556			85,075			(17,886	)		774,745
Cost of oilfield services and rentals		—			—			277,117			44,835			(17,886	)		304,066
Cost of oil and gas sales		—			—			52,469			—			—			52,469
Total cost of services, rentals and sales		—			—			329,586			44,835			(17,886	)		356,535
Depreciation, depletion, amortization and accretion		—			—			70,511			6,962			—			77,473
General and administrative expenses		380			30,556			81,479			9,709			—			122,124
Income from operations		(380	)		(30,556	)		225,980			23,569			—			218,613
Other income (expense):
Interest expense, net		—			(15,204	)		(344	)		(841	)		—			(16,389	)
Interest income		—			2,025			1,246			206			—			3,477
Loss on early extinguishment of debt		—			(12,596	)		—			—			—			(12,596	)
Earnings in equity-method investments, net		—			—			3,834			18			—			3,852
Income before income taxes		(380	)		(56,331	)		230,716			22,952			—			196,957
Income taxes		64,959			—			—			5,945			—			70,904
Net income (loss)	$	(65,339	)	$	(56,331	)	$	230,716		$	17,007		$	—		$	126,053

25

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidating Statements of Operations
Nine Months Ended September 30, 2005
(in thousands)
(unaudited)

										Non-
							Guarantor			Guarantor
	Parent			Issuer			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Oilfield service and rental revenues	$	—		$	—		$	433,710		$	51,939		$	(15,498	)	$	470,151
Oil and gas revenues		—			—			77,197			—			—			77,197
Total revenues		—			—			510,907			51,939			(15,498	)		547,348
Cost of oilfield services and rentals		—			—			231,147			27,554			(15,498	)		243,203
Cost of oil and gas sales		—			—			35,264			—			—			35,264
Total cost of services, rentals and sales		—			—			266,411			27,554			(15,498	)		278,467
Depreciation, depletion, amortization and accretion		—			—			63,221			5,639			—			68,860
General and administrative expenses		355			21,115			74,576			7,087			—			103,133
Reduction in value of assets		—			—			3,244			—			—			3,244
Gain on sale of liftboats		—			—			3,269			—			—			3,269
Income from operations		(355	)		(21,115	)		106,724			11,659			—			96,913
Other income (expense):
Interest expense, net		—			(15,545	)		(5	)		(980	)		—			(16,530	)
Interest income		—			499			866			105			—			1,470
Earnings in equity-method investments, net		—			—			—			1,336			—			1,336
Reduction in value of equity-method investment		—			—			—			(1,250	)		—			(1,250	)
Income before income taxes		(355	)		(36,161	)		107,585			10,870			—			81,939
Income taxes		26,975			—			—			3,343			—			30,318
Net income (loss)	$	(27,330	)	$	(36,161	)	$	107,585		$	7,527		$	—		$	51,621

26

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidating Statements of Cash Flows
Nine Months Ended September 30, 2006
(in thousands)
(unaudited)

										Non-
							Guarantor			Guarantor
	Parent			Issuer			Subsidiaries			Subsidiaries			Consolidated
Cash flows from operating activities:
Net income	$	(65,339	)	$	(56,331	)	$	230,716		$	17,007		$	126,053
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		—			—			70,511			6,962			77,473
Deferred income taxes		(1,734	)		—			—			649			(1,085	)
Stock-based compensation expense		—			1,776			—			—			1,776
Earnings from equity-method investments		—			—			(3,834	)		(18	)		(3,852	)
Write-off of debt acquisition costs		—			2,817			—			—			2,817
Amortization of debt acquisition costs and note discount		—			857			—			—			857
Changes in operating assets and liabilities, net of acquisitions and dispositions:
Receivables		—			1,103			(65,317	)		(11,185	)		(75,399	)
Other — net		(18	)		(2,692	)		(962	)		547			(3,125	)
Accounts payable		—			(480	)		8,161			(356	)		7,325
Accrued expenses		169			9,296			22,605			2,248			34,318
Decommissioning liabilities		—			—			(2,255	)		—			(2,255	)
Income taxes		63,738			—			—			404			64,142
Net cash provided by (used in) operating activities		(3,184	)		(43,654	)		259,625			16,258			229,045
Cash flows from investing activities:
Payments for capital expenditures		—			—			(154,038	)		(11,026	)		(165,064	)
Acquisitions of oil and gas properties, net of cash acquired		—			—			(46,631	)		—			(46,631	)
Acquisitions of businesses, net of cash acquired		—			(9,822	)		—			—			(9,822	)
Cash contributed to equity method investment		—			—			(57,781	)		—			(57,781	)
Cash proceeds from sale of subsidary, net of cash sold		—			18,343			—			—			18,343
Other		—			(2,542	)		—			—			(2,542	)
Intercompany receivables/payables		553			5,806			(1,207	)		(5,152	)		—
Net cash provided by (used in) investing activities		553			11,785			(259,657	)		(16,178	)		(263,497	)
Cash flows from financing activities:
Proceeds from long-term debt		—			295,467			—			—			295,467
Principal payments on long-term debt		—			(200,000	)		—			(405	)		(200,405	)
Payment of debt acquisition costs		—			(6,516	)		—			—			(6,516	)
Proceeds from exercise of stock options		2,631			—			—			—			2,631
Net cash provided by (used in) financing activities		2,631			88,951			—			(405	)		91,177
Effect of exchange rate changes on cash		—			—			—			700			700
Net increase (decrease) in cash		—			57,082			(32	)		375			57,425
Cash and cash equivalents at beginning of period		—			21,414			19,421			13,622			54,457
Cash and cash equivalents at end of period	$	—		$	78,496		$	19,389		$	13,997		$	111,882

27

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

										Non-
							Guarantor			Guarantor
	Parent			Issuer			Subsidiaries			Subsidiaries			Consolidated
Cash flows from operating activities:
Net income	$	(27,330	)	$	(36,161	)	$	107,585		$	7,527		$	51,621
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		—			—			63,221			5,639			68,860
Deferred income taxes		(2,658	)		—			—			(90	)		(2,748	)
Reduction in value of assets		—			—			3,244			—			3,244
Earnings from equity-method investments		—			—			—			(1,336	)		(1,336	)
Reduction in value of equity-method investment		—			—			—			1,250			1,250
Amortization of debt acquisition costs		—			672			—			—			672
Gain on sale of liftboats		—			—			(3,269	)		—			(3,269	)
Changes in operating assets and liabilities, net of acquisitions:
Receivables		—			536			(11,114	)		(7,752	)		(18,330	)
Other — net		(18	)		(1,004	)		1,051			1,090			1,119
Accounts payable		—			273			(809	)		3,460			2,924
Accrued expenses		186			6,261			7,204			2,233			15,884
Decommissioning liabilities		—			—			(8,199	)		—			(8,199	)
Income taxes		22,918			—			—			953			23,871
Net cash provided by (used in) operating activities		(6,902	)		(29,423	)		158,914			12,974			135,563
Cash flows from investing activities:
Payments for capital expenditures		—			—			(86,621	)		(6,339	)		(92,960	)
Acquisitions of oil and gas properties, net of cash acquired		—			—			3,686			—			3,686
Acquisitions of businesses, net of cash acquired		—			(6,435	)		—			—			(6,435	)
Cash proceeds from the sale of liftboats, net		—			—			19,313			—			19,313
Other		—			(1,313	)		(200	)		—			(1,513	)
Intercompany receivables/payables		(10,980	)		94,011			(82,511	)		(520	)		—
Net cash provided by (used in) investing activities		(10,980	)		86,263			(146,333	)		(6,859	)		(77,909	)
Cash flows from financing activities:
Principal payments on long-term debt		—			(8,250	)		—			(405	)		(8,655	)
Proceeds from exercise of stock options		17,882			—			—			—			17,882
Net cash provided by (used in) financing activities		17,882			(8,250	)		—			(405	)		9,227
Effect of exchange rate changes on cash		—			—			—			(771	)		(771	)
Net increase in cash		—			48,590			12,581			4,939			66,110
Cash and cash equivalents at beginning of period		—			3,548			5,173			6,560			15,281
Cash and cash equivalents at end of period	$	—		$	52,138		$	17,754		$	11,499		$	81,391

28

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 and cyclicality of the oil and gas industry, including oil and gas prices and 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, 2005. 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

During the third quarter of 2006, we achieved our highest quarterly levels for revenue, income from operations, net income and diluted earnings per share. Revenue was $290.5 million, income from operations was $88.2 million and net income was $55.2 million, or $0.68 diluted earnings per share.

Our revenue increased in all geographic market areas in which we compete as compared to the second quarter of 2006. The largest increase was internationally, where revenue increased approximately 15% due primarily to a significant increase in rental tools revenue in market areas such as Eastern Canada, West Africa, the Middle East and South America.

In the well intervention segment, revenue was $122.2 million and income from operations was $28.8 million, a 9% and 12% increase, respectively, over the second quarter of 2006. Production-related activity continued to grow over second quarter levels as we saw increased demand for mechanical wireline, coiled tubing, and engineering and project management services. Plug and abandonment activity also increased in the Gulf of Mexico. We were able to increase pricing on plug and abandonments by approximately 15% since the end of the second quarter. Also, our well control subsidiary grew primarily due to increased hurricane recovery work, which has included managing large-scale recovery projects and providing on-site marine and well control engineering services.

In our rental tools segment, revenue was $98.3 million, a 13% increase as compared to the second quarter of 2006, and income from operations was $35.1 million, a 19% increase over the second quarter of 2006. The biggest driver was an increase in international demand for stabilizers, non-magnetic drill collars, accommodations, tubular products and accessories. We experienced strong demand for accommodations in Trinidad and Mexico. In addition, the accommodations business benefited from its expansion into the Rocky Mountains, where we made an acquisition during the second quarter and subsequently added 50 accommodation units to that market area. We saw meaningful demand increases for drill pipe and accessories in offshore Eastern Canada, South America, the Middle

29

East, and West Africa. Finally, demand for stabilizers and non-magnetic drill collars continue to see an increase in business in domestic land markets, deep water Gulf of Mexico, and international markets.

In our marine segment, revenue was $36.0 million, and income from operations was $16.2 million, a 6% and 5% increase, respectively, over the first quarter of 2006. Average daily revenue increased about 5% as compared to the second quarter as we benefited from additional liftboat rate increases that went into effect toward the end of August. Effective utilization, which is utilization excluding shipyard days or other idle days due to repairs and maintenance, was 100% across all liftboat classes in the third quarter, meaning no liftboat was idle for something other than inspections or repairs. Downtime due to shipyard and repair and maintenance days increased about 35% over the second quarter. The biggest increase was in our 145-155 foot class liftboats, which accounted for almost 60% of the downtime during the third quarter. We added a refurbished 200-foot class liftboat to our fleet, giving us five 200-foot class liftboats and 27 total liftboats in our rental fleet.

Revenue from our oil and gas segment was $38.2 million and income from operations was $8.1 million, representing a 14% increase in revenue and 48% increase in income from operations over second quarter 2006 results. Our oil and gas production was about 17% higher than the second quarter of 2006, which helped to offset slightly lower realized oil and gas prices. Third quarter production was approximately 739,000 barrels of oil equivalent (boe), or about 8,000 boe per day, up from approximately 636,000 boe, or 7,000 boe per day in the second quarter of 2006. Our average realized price was $50.58 in the third quarter of 2006 as compared to $52.07 in the second quarter of 2006. The operating income margin increased to 21% from 16% in the second quarter due to higher revenue as well as lower operating expenses. In the second quarter, our operating expenses included $1.3 million in repairs and maintenance expense related to hurricane damage repair work.

Comparison of the Results of Operations for the Three Months Ended September 30, 2006 and 2005

For the three months ended September 30, 2006, our revenues were $290.5 million, resulting in net income of $55.2 million or $0.68 diluted earnings per share. For the three months ended September 30, 2005, revenues were $184.1 million and net income was $9.4 million or $0.12 diluted earnings per share. Revenue and gross margin were higher in the well intervention, rental tools and marine segments as a result of increased production-related projects and drilling activity worldwide, and demand for repair and recovery services we provide to our Gulf of Mexico customers as the result of damage caused by hurricanes in 2004 and 2005. These factors resulted in higher utilization and dayrates for many of our services, liftboats and rental tools. Revenues in our oil and gas segment were higher due to significantly higher production as the third quarter of 2005 production was mainly shut-in due to Hurricanes Katrina and Rita.

The following table compares our operating results for the three months ended September 30, 2006 and 2005. Gross margin is calculated by subtracting cost of services from revenue for each of our four business segments. Oil and gas eliminations represent products and services provided to the oil and gas segment by the Company’s other three segments.

	Revenue									Gross Margin
	2006			2005			Change			2006		%			2005		%			Change
Well Intervention	$	122,205		$	85,848		$	36,357		$	53,767		44	%	$	25,986		30	%	$	27,781
Rental Tools		98,262			61,686			36,576			67,476		69	%		39,694		64	%		27,782
Marine		36,013			18,467			17,546			21,541		60	%		6,628		36	%		14,913
Oil and Gas		38,208			21,764			16,444			18,646		49	%		10,396		48	%		8,250
Less: Oil and Gas Elim		(4,171	)		(3,664	)		(507	)		—		—			—		—			—
Total	$	290,517		$	184,101		$	106,416		$	161,430		56	%	$	82,704		45	%	$	78,726

The following discussion analyzes our results on a segment basis.

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Well Intervention Segment

Revenue for our well intervention segment was $122.2 million for the three months ended September 30, 2006, as compared to $85.8 million for the same period in 2005. This segment’s gross margin percentage increased to 44% for the three months ended September 30, 2006 from 30% for the same period of 2005. We experienced higher revenue for most of our production-related services, especially our well control, coiled tubing, pumping and stimulation, mechanical wireline, hydraulic workover services, and engineering and project management services as production-related activity improved significantly, especially in the Gulf of Mexico. In addition, revenue increased for our plug and abandonment services as many customers continued plugging severely damaged wells and temporarily or permanently plugging other wells to lower their insurance exposure and risk of damage from any future hurricanes. The third quarter of 2005 was negatively impacted by Hurricanes Katrina and Rita. Gross margins improved due to higher utilization and dayrates for many of our services, which generally have high fixed costs.

Rental Tools Segment

Revenue for our rental tools segment for the three months ended September 30, 2006 was $98.3 million, a 59% increase over the same period in 2005. The gross margin percentage slightly increased to 69% for the three months ended September 30, 2006 from 64% for the same period of 2005. We experienced significant increases in revenue from our stabilizers, on-site accommodations, drill pipe and accessories, specialty tubulars and drill collars. The increases are primarily the result of significant increases in activity in the Gulf of Mexico, as well as our international and domestic land expansion efforts. Our international revenue for the rental tools segment has increased 69% to approximately $26.7 million for the quarter ended September 30, 2006 over the same period of 2005. Our largest improvements were in the North Sea, South America and West Africa market areas.

Marine Segment

Our marine segment revenue for the three months ended September 30, 2006 increased 95% over the same period in 2005 to $36.0 million. The gross margin percentage for the three months ended September 30, 2006 increased to 60% from 36% for the same period in 2005. The three months ended September 30, 2006 were characterized by a significant increase in liftboat pricing and utilization due to higher activity levels resulting from increases in Gulf of Mexico production-related activity, and ongoing construction and repair work needed as the result of the damage in the Gulf of Mexico from Hurricanes Katrina and Rita. The third quarter of 2005 was negatively impacted by down-time due to Hurricanes Katrina and Rita in the Gulf of Mexico. The fleet’s average dayrate increased over 84% to approximately $17,500 in the third quarter of 2006 from $9,500 in the third quarter of 2005. The fleet’s average utilization increased to approximately 78% for the third quarter of 2006 from 76% in the same period in 2005.

Oil and Gas Segment

Oil and gas revenues were $38.2 million in the three months ended September 30, 2006, as compared to $21.8 million in the same period of 2005. In the third quarter of 2006, production was approximately 739,000 boe, as compared to approximately 427,000 boe in the third quarter of 2005. Much of the third quarter 2005 production was shut-in beginning in late August of 2005 due to hurricane damages. The gross margin percentage slightly increased to 49% for the three months ended September 30, 2006 from 48% for the same period of 2005.

Depreciation, Depletion, Amortization and Accretion

Depreciation, depletion, amortization and accretion increased to $28.8 million in the three months ended September 30, 2006 from $22.9 million in the same period in 2005. The increase results from the depreciation associated with our 2006 and 2005 capital expenditures primarily in the rental tools segment. The increase also results from additional depletion related to significantly higher production in the third quarter of 2006 as compared to the third quarter of 2005.

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General and Administrative Expenses

General and administrative expenses increased to $44.4 million for the three months ended September 30, 2006 from $37.6 million for the same period in 2005. This increase was primarily related to increased bonus expenses due to our improved performance, increased compensation expenses, and increased expenses related to our geographic expansion, acquisitions and our growth. General and administrative expenses decreased to 15% of revenue for the three months ended September 30, 2006 from 20% for the same period in 2005.

Comparison of the Results of Operations for the Nine months Ended September 30, 2006 and 2005

For the nine months ended September 30, 2006, our revenues were $774.7 million, resulting in net income of $126.1 million or $1.55 diluted earnings per share. This net income includes a loss on early extinguishment of debt of $12.6 million. For the nine months ended September 30, 2005, revenues were $547.3 million, and net income was $51.6 million or $0.65 diluted earnings per share. We experienced significantly higher revenues and gross margins for our well intervention, rental tools and marine segments due to higher pricing and utilization for most products and services offered. Factors driving our improved performance include higher commodity prices resulting in additional production and drilling-related activity worldwide, as well as demand for our services and liftboats that are necessary to assist in repair work needed as the result of the active Gulf of Mexico hurricane seasons of 2004 and 2005. These increases more than offset the lower gross margin in the oil and gas segment due to higher operating expenses as the result of damage from Hurricanes Katrina and Rita.

The following table compares our operating results for the nine months ended September 30, 2006 and 2005. Gross margin is calculated by subtracting cost of services from revenue for each of our four business segments. Oil and gas eliminations represent products and services provided to the oil and gas segment by the Company’s other three segments.

	Revenue								Gross Margin
	2006			2005			Change		2006		%			2005		%			Change
Well Intervention	$	335,953		$	250,983		$	84,970	$	144,160		43	%	$	89,601		36	%	$	54,559
Rental Tools		262,629			175,435			87,194		179,322		68	%		117,032		67	%		62,290
Marine		100,171			56,550			43,621		59,893		60	%		20,315		36	%		39,578
Oil and Gas		87,304			77,197			10,107		34,835		40	%		41,933		54	%		(7,098	)
Less: Oil and Gas Elim		(11,312	)		(12,817	)		1,505		—		—			—		—			—
Total	$	774,745		$	547,348		$	227,397	$	418,210		54	%	$	268,881		49	%	$	149,329

The following discussion analyzes our results on a segment basis.

Well Intervention Segment

Revenue for our well intervention segment was $336.0 million for the nine months ended September 30, 2006, as compared to $251.0 million for the same period in 2005. This segment’s gross margin percentage increased to 43% for the nine months ended September 30, 2006 from 36% for the same period of 2005. We experienced higher revenue for most of our production-related services as pricing and utilization were higher due to increased production-related activity and hurricane-related repair work in the Gulf of Mexico. In addition, revenue increased for our plug and abandonment services as many customers continue to plug severely damaged wells and temporarily or permanently plug other wells to lower their insurance exposure and risk of damage from any future hurricanes.

Rental Tools Segment

Revenue for our rental tools segment for the nine months ended September 30, 2006 was $262.6 million, a 50% increase over the same period in 2005. The gross margin percentage increased slightly to 68% for the three months ended September 30, 2006 from 67% for the same period of 2005. We experienced significant increases in revenue from our stabilizers, on-site accommodations, drill pipe and accessories, specialty tubulars and drill collars. The increases are primarily the result of significant increases in activity in the Gulf of Mexico, domestic land markets, as well as our international expansion efforts. Our international revenue for the rental tools segment has increased

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over 67% to approximately $63.2 million for the nine months ended September 30, 2006 over the same period of 2005.

Marine Segment

Our marine segment revenue for the nine months ended September 30, 2006 increased 77% over the same period in 2005 to $100.2 million. The gross margin percentage for the nine months ended September 30, 2006 increased to 60% from 36% for the same period in 2005. The nine months ended September 30, 2006 were characterized by a significant increase in liftboat pricing and utilization due to higher activity levels resulting from increases in Gulf of Mexico production-related activity and ongoing construction and repair work needed as the result of the damage in the Gulf of Mexico from Hurricanes Katrina and Rita. The fleet’s average dayrate increased over 100% to approximately $15,800 in the first nine months of 2006 from $7,800 in the same period of 2005. The fleet’s average utilization increased to approximately 82% for the nine months ended September 30, 2006 from 75% in the same period in 2005. The nine months ended September 30, 2005 also included five months of rental activity from the 105-foot and the 120 to 135-foot class liftboats, which were sold June 1, 2005.

Oil and Gas Segment

Oil and gas revenues were $87.3 million in the nine months ended September 30, 2006, as compared to $77.2 million in the same period of 2005. In the nine months ended September 30, 2006, production was approximately 1,730,000 boe, as compared to approximately 1,690,000 boe in the same period of 2005. The gross margin percentage decreased to 40% in the nine months ended September 30, 2006 from 54% in the same period of 2005 due to the shut-in production through April 2006, increased insurance cost and ongoing repair costs related to Hurricanes Katrina and Rita.

Depreciation, Depletion, Amortization and Accretion

Depreciation, depletion, amortization and accretion increased to $77.5 million in the nine months ended September 30, 2006 from $68.9 million in the same period in 2005. The increase results from the depreciation associated with our 2006 and 2005 capital expenditures primarily in the rental tools segment.

General and Administrative Expenses

General and administrative expenses increased to $122.1 million for the nine months ended September 30, 2006 from $103.1 million for the same period in 2005. This increase was primarily related to increased bonus expenses due to our improved performance; increased compensation expenses from our new long-term incentive plan established late in the second quarter of 2005; and increased expenses related to our geographic expansion, oil and gas acquisitions and our growth. General and administrative expenses decreased to 16% of revenue for the nine months ended September 30, 2006 from 19% for the same period in 2005.

Liquidity and Capital Resources

In the nine months ended September 30, 2006, we generated net cash from operating activities of $229.0 million as compared to $135.6 million in the same period of 2005. 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 $111.9 million at September 30, 2006 compared to $54.5 million at December 31, 2005.

We made $165.1 million of capital expenditures during the nine months ended September 30, 2006, of which approximately $81.1 million was used to expand and maintain our rental tool equipment inventory. We also made $29.4 million of capital expenditures in our oil and gas segment and $51.6 million of capital expenditures to expand and maintain the asset base of our well intervention and marine segments, including $5.9 million related to an anchor handling tug, $20.6 million related to the completion of our first derrick barge and $3.0 million of progress payments related to the construction of another derrick barge. In addition, we made $3.0 million of capital expenditures on construction and improvements to our facilities.

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During the nine months ending September 30, 2006, we paid $46.6 million to acquire producing oil and gas properties located on five offshore Gulf of Mexico leases. We also purchased two businesses in order to expand the housing units offered by our rental tools segment into Wyoming and expand the snubbing services offered by our well intervention segment in Australia.

We acquired a 40% interest in Coldren Resources which acquired substantially all of Noble’s shallow water Gulf of Mexico oil and gas properties. We have made a total investment in Coldren Resources of approximately $57.7 million as of September 30, 2006. We do not anticipate additional cash investments into Coldren Resources.

During the first quarter of 2006, we sold our environmental cleaning subsidiary for approximately $18.3 million.

On July 27, 2006, we took delivery of an 880-ton derrick barge. The final payment of $13.3 million was made upon its delivery and acceptance. The derrick barge and related anchor handling tug are chartered to a third party until October 31, 2007.

In July 2006, we contracted to construct a derrick barge that will be sold to a third party for approximately $54 million. We expect to take delivery of the derrick barge and sell it to the third party during the first quarter of 2008. We receive monthly payments from the purchaser in accordance with the terms of the sales contract. In turn, we issue letters of credit to the purchaser in equal amounts to guarantee our performance of the contract. We have entered into fixed-price contracts to construct this second derrick barge and its 880-ton offshore mast crane. Our payment obligation for the construction of the barge is secured by letters of credit that are posted upon performance milestones and are payable upon the barge’s delivery and our acceptance. The contract for the crane requires periodic progress payments with final payment due upon completion of the contract. Revenue and cost associated with the sale contract is recorded on the percentage-of-completion method using a milestone-based measure focused on engineering estimates and manufacturing progress. This method is used because we believe it is the most meaningful measure of the extent of progress toward completion. This methodology requires us to make estimates regarding our progress against the project schedule and estimated completion date, both of which impact the amount of revenue and gross margin we recognize in each reporting period. Contract costs mainly include sub-contract and program management costs. Provisions for any anticipated losses will be recorded in full when such losses become evident. For the three and nine months ended September 30, 2006, the Company recognized approximately $430,000 of revenues and approximately $154,000 of gross profit on this contract.

In July 2006, we contracted to construct a third derrick barge to support our decommissioning and construction operations. We expect to take delivery of this barge in the second quarter of 2008. We have entered into fixed-price contracts to construct this derrick barge and its 880-ton offshore mast crane. Our payment obligation for the construction of the barge is secured by letters of credit that are posted upon performance milestones and are payable upon the barge’s delivery and our acceptance. The contract for the crane requires periodic progress payments with final payment due upon completion of the contract. We intend to utilize this construction barge to support our removal projects in the Gulf of Mexico market area for both third party customers and our subsidiary, SPN Resources.

In September 2006, we entered into a definitive merger agreement to acquire Warrior for a total estimated purchase price of approximately $319.0 million. The total consideration is comprised of cash payments of approximately $175.2 million ($14.50 per share of outstanding Warrior common stock), $133.8 million in equity (approximately 5.3 million shares of our common stock, at an exchange ratio of 0.452 of our common stock for each share of Warrior common stock, multiplied by our share price of $25.39, the average closing market price per share for the five trading day period beginning two trading days before the merger announcement date of September 25, 2006), and approximately $10 million of estimated direct transaction costs. Warrior is a natural gas and oil well services company that provides wireline and well intervention services to exploration and production companies. Warrior’s operations are concentrated in the major onshore and offshore natural gas and oil producing areas of the U.S. The transaction is subject to customary closing conditions, and is expected to close in the middle of December 2006.

We currently believe that we will make approximately $75 to $80 million of capital expenditures, excluding acquisitions and targeted asset purchases, during the remaining three months of 2006 to expand our rental tool asset base and perform workovers on SPN Resources’ oil and gas properties. We believe that our current working capital,

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cash generated from our operations and availability under our revolving credit facility will provide sufficient funds for our identified capital projects.

We have a bank credit facility consisting of a $150 million revolving credit facility, with an option to increase it to $250 million. We are currently in the process of exercising the option to increase the credit facility to the $250 million to accommodate increasing letters of credit for the construction of the new derrick barges. Any amounts outstanding under the revolving credit facility are due on October 31, 2008. At September 30, 2006, we had no amounts outstanding under the bank credit facility, but we had approximately $21.2 million of letters of credit outstanding, which reduces the borrowing availability under this credit facility. The credit facility bears interest at a LIBOR rate plus margins that depend on our leverage ratio. Indebtedness under the credit facility is secured by substantially all of our assets, including the pledge of the stock our principal subsidiaries. The credit facility contains customary events of default and requires that we satisfy various financial covenants. It also limits our capital expenditures, our ability to pay dividends or make other distributions, make acquisitions, create liens, incur additional indebtedness or assume additional decommissioning liabilities.

We have $17.0 million outstanding at September 30, 2006 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.

In the second quarter of 2006, we completed a tender offer for approximately 97.6% of our $200 million outstanding of 8 7/8% unsecured senior notes due 2011. The cash consideration for the tender offer was $1,045.63 per $1,000 in aggregate principal amount of senior notes tendered. In conjunction with the tender offer, we also received consents to amend the indenture pursuant to which the senior notes were issued to eliminate from the indenture substantially all of the restrictive covenants and certain events of default. After the tender offer was completed, we redeemed the remaining outstanding senior notes in accordance with the indenture at the redemption price of $1,044.38 per $1,000 of the principal amount redeemed. We recognized a loss on the early extinguishment of debt of approximately $12.6 million, which included the tender premiums, redemption premiums, fees and expenses and the write-off of the remaining unamortized debt acquisition costs associated with these notes.

We issued $300 million of 6 7/8% unsecured senior notes due 2014. We used the net proceeds to refinance the 8 7/8% senior notes due 2011 and related tender and redemption premiums, fees and related expenses, and to fund the equity investment in Coldren Resources. The indenture governing the notes requires semi-annual interest payments, on every June 1^st and December 1^st through the maturity date of June 1, 2014. The indenture contains certain covenants that, among other things, restrict us from incurring, additional debt, repurchasing capital stock, paying dividends or making other distributions, incurring liens, selling assets or entering into certain mergers or acquisitions.

In the third quarter and in connection with the Warrior acquisition, we obtained a commitment for a seven year $200 million secured term loan to fund the cash portion of the merger consideration and refinance a portion of Warrior’s existing debt. The term loan is expected to bear interest, at our election, at the prime rate plus 50 basis points or LIBOR plus up to 225 basis points and will be payable in quarterly installments of 0.25% of the initial term amount for the first six years with the balance due in the seventh year.

The following table summarizes our contractual cash obligations and commercial commitments at September 30, 2006 (amounts in thousands) for our long-term debt (including estimated interest payments), decommissioning liabilities, operating leases and contractual obligations. The decommissioning liability amounts do not give any effect to our contractual right to receive amounts from third parties, which is approximately $31.1 million, when decommissioning operations are performed. The vessel construction liability amounts do not give any effect to our contractual right to receive payments from a third-party customer, which is approximately $50.3 million. We do not have any other material obligations or commitments.

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	Remaining
	Three
	Months
Description	2006		2007		2008		2009		2010		2011		Thereafter
Long-term debt, including estimated interest payments	$	12,125	$	22,492	$	22,440	$	22,388	$	22,336	$	22,283	$	370,578
Decommissioning liabilities		10,112		25,586		5,722		2,346		10,172		29,083		38,872
Operating leases		1,621		5,793		3,137		1,628		1,047		713		12,715
Vessel construction		1,986		25,758		45,432		—		—		—		—
Total	$	25,844	$	79,629	$	76,731	$	26,362	$	33,555	$	52,079	$	422,165

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 several acquisitions. At September 30, 2006, the maximum additional consideration payable for these acquisitions was approximately $2.4 million. These amounts are not classified as liabilities under generally accepted accounting principles and are not reflected in our financial statements until the amounts are fixed and determinable. When amounts are determined, they are capitalized as part of the purchase price of the related acquisition. We do not have any other financing arrangements that are not required under generally accepted accounting principles to be reflected in our financial statements.

We 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 February 2006, the Financial Accounting Standards Board issued its Statement of Financial Accounting Standards No. 155 (FAS No. 155), “Accounting for Certain Hybrid Financial Instruments – an amendment of FASB Statements No. 133 and 140.” FAS No. 155 simplifies accounting for certain hybrid financial instruments by permitting fair value remeasurement for any hybrid instrument that contains an embedded derivative that otherwise would require bifurcation and eliminates a restriction on the passive derivative instruments that a qualifying special-purpose entity may hold. FAS No. 155 is effective for all financial instruments acquired, issued or subject to a remeasurement (new basis) event occurring after the beginning of an entity’s first fiscal year that begins after September 15, 2006. The adoption of FAS No. 155 will have no impact on our results of operations or our financial position.

In July 2006, the Financial Accounting Standards Board issued FASB Interpretation No. 48 (FIN No. 48), “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109.” FIN No. 48 provides guidance on measurement and recognition in accounting for income tax uncertainties and also requires expanded financial statement disclosure. This interpretation is effective for fiscal years beginning after December 15, 2006. We are currently evaluating the impact, if any, that FIN No. 48 will have on our results of operations and financial position.

In September 2006, the Financial Accounting Standards Board issued its Statement of Financial Accounting Standards No. 157 (FAS No. 157), “Fair Value Measurements”. FAS No. 157 establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. FAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. We are currently evaluating the impact that FAS No. 157 will have on our results of operations and financial position.

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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 production. We have not hedged any of our natural gas production. Our hedging contracts for a portion of our oil production expired on August 31, 2006, and there are no outstanding contracts as of the date of this Form 10-Q.

Interest Rate Risk

At September 30, 2006, none of our long-term debt outstanding had variable interest rates, and we had no interest rate risks at that time.

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, 2006	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

Exhibit No.		Description of Exhibit
	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.