Edgar Filing: SUPERIOR ENERGY SERVICES INC

e10vq

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 March 31, 2006


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. Yes þ No o

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

Large accelerated filer þ Accelerated filer o Non-accelerated o

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

The number of shares of the registrant’s common stock outstanding on May 3, 2006 was 79,794,163.

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Quarterly Report on Form 10-Q for
the Quarterly Period Ended March 31, 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	18
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	23
Item 4.	Controls and Procedures	24

PART II OTHER INFORMATION

Item 1A.	Risk Factors	25
Item 6.	Exhibits	26
Officer's certification pursuant to Section 302
Officer's certification pursuant to Section 302
Officer's certification pursuant to Section 906
Officer's certification pursuant to Section 906

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidated Balance Sheets
March 31, 2006 and December 31, 2005
(in thousands, except share data)


	3/31/06			12/31/05
	(Unaudited)			(Audited)
ASSETS
Current assets:
Cash and cash equivalents	$	68,574		$	54,457
Accounts receivable — net		212,891			196,365
Current portion of notes receivable		4,621			2,364
Prepaid insurance and other		66,335			51,116


Total current assets		352,421			304,302


Property, plant and equipment — net		541,323			534,962
Goodwill — net		217,532			220,064
Notes receivable		25,874			29,483
Other assets — net		9,551			8,439


Total assets	$	1,146,701		$	1,097,250

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	37,553		$	42,035
Accrued expenses		77,460			69,926
Income taxes payable		25,797			11,353
Fair value of commodity derivative instruments		9,119			10,792
Current portion of decommissioning liabilities		13,749			14,268
Current maturities of long-term debt		810			810


Total current liabilities		164,488			149,184


Deferred income taxes		99,671			97,987
Decommissioning liabilities		102,020			107,641
Long-term debt		216,596			216,596
Other long-term liabilities		3,308			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, 79,741,924 shares at March 31, 2006, and 79,499,927 shares at December 31, 2005		80			79
Additional paid in capital		431,019			428,507
Accumulated other comprehensive loss, net		(3,353	)		(4,916	)
Retained earnings		132,872			100,704


Total stockholders’ equity		560,618			524,374


Total liabilities and stockholders’ equity	$	1,146,701		$	1,097,250


		See accompanying notes to consolidated financial statements.

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidated Statements of Operations
Three Months Ended March 31, 2006 and 2005
(in thousands, except per share data)
(unaudited)


	2006			2005
Oilfield service and rental revenues	$	206,998		$	147,292
Oil and gas revenues		15,471			25,955

Total revenues		222,469			173,247


Cost of oilfield services and rentals		93,255			73,613
Cost of oil and gas sales		14,205			12,805

Total cost of services, rentals and sales		107,460			86,418


Depreciation, depletion, amortization and accretion		22,915			22,397
General and administrative expenses		37,651			32,384


Income from operations		54,443			32,048

Other income (expense):
Interest expense, net		(4,844	)		(5,575	)
Interest income		663			324
Equity in income of affiliates, net		—			519


Income before income taxes		50,262			27,316

Income taxes		18,094			10,107


Net income	$	32,168		$	17,209


Basic earnings per share	$	0.40		$	0.22


Diluted earnings per share	$	0.40		$	0.22


Weighted average common shares used in computing earnings per share:
Basic		79,639			77,381
Incremental common shares from stock options		1,329			1,582
Incremental common shares from restricted stock units		20			10

Diluted		80,988			78,973


		See accompanying notes to consolidated financial statements.

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidated Statements of Cash Flows
Three Months Ended March 31, 2006 and 2005
(in thousands)
(unaudited)


	2006			2005
Cash flows from operating activities:
Net income	$	32,168		$	17,209
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		22,915			22,397
Deferred income taxes		1,034			3,135
Stock based compensation expense		322			—
Equity in income of affiliates		—			(519	)
Changes in operating assets and liabilities, net of acquisitions:
Receivables		(20,032	)		(8,636	)
Other — net		(12,817	)		(1,265	)
Accounts payable		(3,687	)		(11,691	)
Accrued expenses		7,553			11,184
Decommissioning liabilities		(2,255	)		(5,426	)
Income taxes		15,136			6,939


Net cash provided by operating activities		40,337			33,327


Cash flows from investing activities:
Payments for capital expenditures		(44,489	)		(30,180	)
Acquisitions of businesses, net of cash acquired		—			(5,273	)
Cash proceeds from sale of subsidary, net of cash sold		18,343			—
Other		(1,695	)		(1,105	)


Net cash used in investing activities		(27,841	)		(36,558	)


Cash flows from financing activities:
Principal payments on long-term debt		—			(2,750	)
Proceeds from exercise of stock options		1,467			5,430


Net cash provided by financing activities		1,467			2,680


Effect of exchange rate changes on cash		154			(86	)


Net increase (decrease) in cash		14,117			(637	)

Cash and cash equivalents at beginning of period		54,457			15,281


Cash and cash equivalents at end of period	$	68,574		$	14,644


		See accompanying notes to consolidated financial statements.

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements
Three Months Ended March 31, 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 financial statements and notes thereto included in Superior Energy Services, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2005 and Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The financial information of Superior Energy Services, Inc. and subsidiaries (the Company) for the three months ended March 31, 2006 and 2005 has not been audited. However, in the opinion of management, all adjustments (which include only normal recurring adjustments) necessary to present fairly the results of operations for the periods presented have been included therein. The results of operations for the first three 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 1999 Incentive Plan and the 1995 Incentive Plan were fully-vested by March 31, 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 and restricted stock units were expensed as incurred.

Stock Options

The Company has granted non-qualified stock options under its various stock incentive plans. The options generally vest in equal installments on the anniversary of the respective grant for three consecutive years and expire on the

tenth anniversary of the respective date of grant. Non-vested options are generally subject to forfeiture in the event of termination of employment. On February 23, 2006, the Company granted 212,600 non-qualified stock options 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 grants made during the first quarters of 2006 and 2005 and the related assumptions used to calculate the fair value:


	Three Months Ended
	March 31, 2006			March 31, 2005
	Actual			Pro Forma
Weighted-average fair value of grants	$	11.58			*

Black-Scholes-Merton Assumptions:
Risk free interest rate		4.57	%		*
Expected life (years)		5.1			*
Volatility		45.42	%		*
Dividend yield		—			*


		(* There were no stock option grants during the three months ended March 31, 2005.)

The Company’s compensation expense related to stock options for the three months ended March 31, 2006 was approximately $191,000, which is reflected in general and administrative expenses. This compensation expense reduced net income, on an after tax basis, by approximately $122,000, which did not have a material impact on basic or diluted earnings per share. No compensation expense related to options was recorded during the three months ended March 31, 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):


	Three Months
	Ended March 31,
	2005
Net income, as reported	$	17,209
Stock-based employee compensation expense, net of tax		(88	)


Pro forma net income	$	17,121

Basic earnings per share:
Earnings, as reported	$	0.22
Stock-based employee compensation expense, net of tax		—


Pro forma earnings per share	$	0.22


Diluted earnings per share:
Earnings, as reported	$	0.22
Stock-based employee compensation expense, net of tax		—


Pro forma earnings per share	$	0.22

The following table summarizes stock option activity for the three months ended March 31, 2006:


						Weighted
						Average
				Weighted		Remaining		Aggregate
	Number of			Average		Contractual		Intrinsic Value
	Options			Option Price		Term (in years)		(in thousands)
Outstanding at December 31, 2005		3,893,633		$	11.44
Granted		212,600		$	24.99
Exercised		(137,954	)	$	10.63
Forfeited		(10,667	)	$	16.92


Outstanding at March 31, 2006		3,957,612		$	12.18		7.5	$	57,829


Exercisable at March 31, 2006		3,736,679		$	11.45		7.4	$	57,305

The aggregate intrinsic value in the table above represents the total pre-tax intrinsic value (the difference between our closing stock price on March 31, 2006 and the option price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on March 31, 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 three months ended March 31, 2006 (the difference between the stock price upon exercise and the option price) was approximately $2.0 million. The Company received approximately $1.5 million during the three months ended March 31, 2006 from employee stock option exercises. The Company expects to reduce its future tax payments by approximately $0.7 million as the result of the intrinsic value of options exercised during the three months ended March 31, 2006. Due to the I.R.S. administrative relief provisions related to Hurricanes Katrina and Rita, the Company is not required to pay income taxes until August 2006. The Company expects to recognize this benefit in the cash flow statement as a cash flow from financing activities when the related tax payments are made during the third quarter of 2006.

The following table summarizes non-vested stock option activity for the three months ended March 31, 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		(124,912	)	$	3.62
Forfeited		(667	)	$	3.62


Non-vested at March 31, 2006		220,933		$	11.29

As of March 31, 2006, there was approximately $2.4 million of unrecognized compensation expense related to non-vested stock options. The Company expects to recognize approximately $0.7 million, $0.8 million, $0.8 million and $0.1 million during the remainder of 2006, the years 2007, 2008 and 2009, respectively, for these non-vested stock options.

Restricted Stock

On February 23, 2006, the Company granted 104,043 shares of restricted stock to its employees as part of its long-term incentive program. These shares of restricted stock vest in equal annual installments on the anniversary of the respective grant for three consecutive years, and unvested shares are subject to forfeiture in the event of 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 for the three months ended March 31, 2006 was approximately $131,000, which is reflected in general and administrative expenses.

A summary of the status of the shares of restricted stock for the three months ended March 31, 2006 is presented in the table below:


				Weighted
				Average
	Number of			Grant Date
	Shares			Fair Value
Non-vested at December 31, 2005		24,000		$	22.24
Granted		104,043		$	24.99
Vested		(8,000	)	$	22.24
Forfeited		(1,200	)	$	24.99


Non-vested at March 31, 2006		118,843		$	24.62

As of March 31, 2006, there was approximately $2.8 million of unrecognized compensation expense related to non-vested restricted stock shares. The Company expects to recognize approximately $0.8 million, $1.0 million, $0.9 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.

Restricted Stock Units

In 2004, the Superior Energy Services, Inc. 2004 Directors Restricted Stock Units Plan was approved by the Company’s stockholders. This plan provides that each non-employee director is granted a number of restricted stock

units having an aggregate value of $30,000, with the exact number of units determined by dividing $30,000 by the fair market value of the Company’s common stock on the day of the annual stockholders’ meeting. In addition, upon 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, 19,998 restricted stock units are outstanding at March 31, 2006.

Performance Share Units

On February 23, 2006, the Company awarded 33,845 performance share units (“PSUs”) to its employees as part of its long-term incentive program. The performance period for the PSUs runs from January 1, 2006 through December 31, 2008. The two performance measures applicable to all participants are the Company’s return on invested capital and total shareholder return relative to those of the Company’s pre-defined “peer group.” Participants can earn from $0 to $200 per PSU, as determined by the Company’s achievement of the performance measures. 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. The Company also has 31,821 PSUs outstanding from the June 24, 2005 grant related to the Company’s performance period from January 1, 2005 through December 31, 2007. The Company’s compensation expense related to all outstanding PSUs for the three months ended March 31, 2006 was approximately $0.5 million, which is reflected in general and administrative 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 February 2006, the Company sold its subsidiary Environmental Treatment Team, L.L.C., (ETT) for approximately $18.7 million in cash (exclusive of $0.4 million of cash sold). The Company reduced the net asset value of ETT by $3.8 million in 2005 to its approximate sales price. For the quarters ended March 31, 2006 and 2005, revenue from ETT was approximately $4.6 million and $6.2 million, respectively, and operating income (loss) was approximately $29,000 and ($186,000), 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 purchase price allocated to net assets was approximately $1.3 million, and no goodwill was recorded. The results of operations have been included from the acquisition date.

Also in 2005, the Company’s subsidiary, SPN Resources, LLC, 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 preliminarily recorded notes receivable of approximately $2.4 million, decommissioning liabilities of $11.5 million and oil and gas producing assets were recorded at their estimated fair value of $5.4 million.

Most of the Company’s business acquisitions have involved additional contingent consideration based upon a multiple of the acquired companies’ respective average earnings before interest, income taxes, depreciation and amortization (EBITDA) over a three-year period from the respective date of acquisition. As of March 31, 2006, the maximum additional consideration payable for the Company’s prior acquisitions was approximately $2.4 million,

and will be determined and payable through 2008. These amounts are not classified as liabilities under generally accepted accounting principles and are not reflected in the Company’s financial statements until the amounts are fixed and determinable. The Company does not have any other financing arrangements that are not required under generally accepted accounting principles to be reflected in its financial statements. When the amounts are determined, they are capitalized as part of the purchase price of the related acquisition.

Subsequent Events

In the second quarter of 2006, the Company acquired two businesses for an aggregate of $9.8 million in cash consideration in order to geographically expand as well as enhance the products and services offered by its rental tools segment and well intervention segment. These acquisitions will be accounted for as purchases.

In April 2006, SPN Resources, LLC, 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 expects to record decommissioning liabilities of approximately $3.7 million.

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

Summarized financial information concerning the Company’s segments for the three months ended March 31, 2006 and 2005 is shown in the following tables (in thousands):

Three Months Ended March 31, 2006


										Oil & Gas
	Well		Rental							Eliminations			Consolidated
	Intervention		Tools		Marine		Oil & Gas			& Unallocated			Total

Revenues	$	102,073	$	77,774	$	30,207	$	15,471		$	(3,056	)	$	222,469
Cost of services, rentals and sales		60,000		24,298		12,013		14,205			(3,056	)		107,460
Depreciation, depletion, amortization and accretion		4,535		11,713		2,152		4,515			—			22,915
General and administrative expense		17,868		15,266		2,898		1,619			—			37,651
Income (loss) from operations		19,670		26,497		13,144		(4,868	)		—			54,443
Interest expense, net		—		—		—		—			(4,844	)		(4,844	)
Interest income		—		—		—		300			363			663


Income (loss) before income taxes	$	19,670	$	26,497	$	13,144	$	(4,568	)	$	(4,481	)	$	50,262

Three Months Ended March 31, 2005


									Oil & Gas
	Well		Rental						Eliminations			Consolidated
	Intervention		Tools		Marine		Oil & Gas		& Unallocated			Total

Revenues	$	80,116	$	52,627	$	19,798	$	25,955	$	(5,249	)	$	173,247
Cost of services, rentals and sales		49,398		17,534		11,930		12,805		(5,249	)		86,418
Depreciation, depletion, amortization and accretion		4,579		9,910		2,103		5,805		—			22,397
General and administrative expense		16,203		12,594		2,108		1,479		—			32,384
Income (loss) from operations		9,936		12,589		3,657		5,866		—			32,048
Interest expense, net		—		—		—		—		(5,575	)		(5,575	)
Interest income		—		—		—		292		32			324
Equity in income of affiliates, net		—		519		—		—		—			519


Income (loss) before income taxes	$	9,936	$	13,108	$	3,657	$	6,158	$	(5,543	)	$	27,316

Identifiable Assets


	Well		Rental								Consolidated
	Intervention		Tools		Marine		Oil & Gas		Unallocated		Total

March 31, 2006	$	339,330	$	420,412	$	194,140	$	184,018	$	8,801	$	1,146,701


December 31, 2005	$	332,996	$	405,527	$	203,718	$	147,667	$	7,342	$	1,097,250

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):

Revenues:


	Three Months Ended March 31,
	2006		2005
United States	$	189,005	$	151,544
Other Countries		33,464		21,703


Total	$	222,469	$	173,247

Long-Lived Assets:

	March 31,		December 31,
	2006		2005
United States	$	497,245	$	492,602
Other Countries		44,078		42,360


Total	$	541,323	$	534,962

(6) 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 balance outstanding on the revolving credit facility is due on October 31, 2008. At March 31, 2006, the Company had no amounts outstanding under this bank credit facility, but it had approximately $20.2 million of letters of credit outstanding, which reduce 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. At March 31, 2006, the Company was in compliance with all such covenants.

The Company has $17.4 million outstanding at March 31, 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 payable in equal semi-annual installments of $405,000, on every June 3rd and December 3rd through June 3, 2027. The Company’s obligations are secured by mortgages on the two liftboats. In accordance with this agreement, the Company is required to comply with certain covenants and restrictions, including the maintenance of minimum net worth and debt-to-equity requirements. At March 31, 2006, the Company was in compliance with all such covenants. This long-term financing ranks equally with the bank credit facility.

The Company also has outstanding $200 million of 8 7/8% unsecured senior notes due 2011. The indenture governing the notes requires semi-annual interest payments, on every May 15^th and November 15^th through the maturity date of May 15, 2011. The indenture governing the senior notes contains certain covenants that, among other things, prevent the Company from incurring additional debt, paying dividends or making other distributions, unless its ratio of cash flow to interest expense is at least 2.25 to 1, except that the Company may incur additional debt in addition to the senior notes in an amount equal to 30% of its net tangible assets as defined, which was approximately $220 million at March 31, 2006. The indenture also contains covenants that restrict the Company’s ability to create certain liens, sell assets or enter into certain mergers or acquisitions. At March 31, 2006, the Company was in compliance with all such covenants.

Subsequent Event

On May 5, 2006, the Company announced that it has commenced a tender offer for all of its outstanding senior notes. In conjunction with the tender offer, the Company is also soliciting 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. The cash consideration for the tender offer is $1,045.63 per $1,000 in aggregate principal

amount of senior notes tendered. After the expiration of the tender offer, the Company intends to redeem any remaining outstanding senior notes at the redemption price of 104.438% of the principal amount redeemed.

The Company intends to obtain new financing through the issuance of up to $300,000,000 new unsecured senior notes, the proceeds of which will be used to fund the purchase price of the tender offer, to redeem any senior notes not purchased in the tender offer and to provide additional working capital. The tender offer is conditioned on, among other things, receipt of consents from holders of a majority of the outstanding principal amount of senior notes, the Company’s completion of the issuance of the new unsecured senior notes on the terms and conditions acceptable to the Company, and the amendment of the terms of the bank credit facility to allow for the issuance of the new unsecured senior notes. Subject to the satisfaction of all the terms and conditions, the Company currently expects to complete the tender offer in late May 2006. Upon completion of this transaction, the Company expects to recognize a loss from the early extinguishment of long-term debt of approximately $12 to $13 million.

(7) Hedging Activities

The Company has entered into hedging transactions with major financial institutions to secure a commodity price 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 has used financially-settled crude oil swaps and zero-cost collars that provide floor and ceiling prices with varying upside price participation. The Company’s swaps and zero-cost collars are designated and accounted for as cash flow hedges. The Company has not hedged any of its natural gas production.

With a financially-settled swap, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the hedged price for the transaction, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. With a zero-cost collar, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price of the collar, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar. The Company recognizes the fair value of all derivative instruments as assets or liabilities on the balance sheet. Changes in the fair value of cash flow hedges are recognized, to the extent the hedge is effective, in other comprehensive income until the hedged item is settled and recorded in revenue. For the three months ended March 31, 2006, hedging settlement payments reduced oil revenues by approximately $3.8 million, and no gains or losses were recognized due to hedge ineffectiveness.

The Company had the following hedging contracts as of March 31, 2006:


Crude Oil Positions
	Instrument	Strike	Volume (Bbls)
Remaining Contract Term	Type	Price (Bbl)	Daily	Total (Bbls)
4/06 - 8/06	Swap	$39.45	1,000	184,000
4/06 - 8/06	Collar	$35.00/$45.60	1,000	184,000

Based on the futures prices quoted at March 31, 2006, the Company expects to reclassify net losses of approximately $5.7 million, net of taxes, into earnings related to the derivative contracts through August 2006 during the remaining term of the contracts; however, actual gains or losses recognized may differ materially depending on the movement of commodity pricing over the next twelve months.

(8) Decommissioning Liabilities

The Company records estimated future decommissioning liabilities related to its oil and gas producing properties pursuant to the provisions of Statement of Financial Accounting Standards No. 143 (FAS No. 143), “Accounting for Asset Retirement Obligations.” FAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation (decommissioning liabilities) in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. Subsequent to initial measurement, the decommissioning

liability is required to be accreted each period to present value. The Company’s decommissioning liabilities consist of costs related to the plugging of wells, the removal of facilities and equipment, including pipeline, and site restoration on oil and gas properties.

The Company estimates the cost that would be incurred if it contracted an unaffiliated third party to plug and abandon wells, abandon the pipelines, decommission and remove the platforms and pipelines and restore the sites of its oil and gas properties, and uses that estimate to record its proportionate share of the decommissioning liability. In estimating the decommissioning liability, the Company performs detailed estimating procedures, analysis and engineering studies. Whenever practical, the Company utilizes its own equipment and labor services to perform well abandonment and decommissioning work. When the Company performs these services, all recorded intercompany revenues are eliminated in the consolidated financial statements. The recorded decommissioning liability associated with a specific property is fully extinguished when the property is abandoned. The recorded liability is first reduced by all cash expenses incurred to abandon and decommission the property. If the recorded liability exceeds (or is less than) the Company’s out-of-pocket costs, then the difference is reported as income (or loss) within revenue during the period in which the work is performed. The Company reviews the adequacy of its decommissioning liabilities whenever indicators suggest that the estimated cash flows needed to satisfy the liability have changed materially. The timing and amounts of these 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 three months ended March 31, 2006, which caused a reduction in the decommissioning liability of approximately $5.1 million. The following table summarizes the activity for the Company’s decommissioning liabilities for the three months ended March 31, 2006 and 2005 (amounts in thousands):


	Three Months Ended
	March 31,
	2006			2005
Total decommissioning liabilities at December 31, 2005 and 2004, respectively	$	121,909		$	114,018
Liabilities acquired and incurred		—			—
Liabilities settled		(2,255	)		(5,426	)
Accretion		1,178			1,098
Revision in estimated liabilities		(5,063	)		199


Total decommissioning liabilities at March 31, 2006 and 2005, respectively		115,769			109,889
Current portion of decommissioning liabilities at March 31, 2006 and 2005, respectively		13,749			25,730


Long-term portion of decommissioning liabilities at March 31, 2006 and 2005, respectively	$	102,020		$	84,159

(9) 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.

(10) Prepaid Insurance and Other

Prepaid insurance and other includes approximately $37.4 million and $23.9 million in insurance receivables at March 31, 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 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.

(11) Other Comprehensive Income

The following tables reconcile the change in accumulated other comprehensive income (loss) for the three months ended March 31, 2006 and 2005 (amounts in thousands):


	Three Months Ended
	March 31,
	2006			2005
Accumulated other comprehensive income (loss), December 31, 2005 and 2004, respectively	$	(4,916	)	$	2,884

Other comprehensive income (loss):
Other comprehensive income (loss), net of tax Hedging activities:
Hedging activities:
Adjustment for settled contracts, net of tax of $1,323 in 2006 and $314 in 2005		2,253			534
Changes in fair value of outstanding hedging positions, net of tax of ($704) in 2006 and ($5,047) in 2005		(1,198	)		(8,594	)
Foreign currency translation adjustment		508			(721	)


Total other comprehensive income (loss)		1,563			(8,781	)


Accumulated other comprehensive loss, March 31, 2006 and 2005, respectively	$	(3,353	)	$	(5,897	)

(12) 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.

(13) Accounting Pronouncements

In March 2005, the Financial Accounting Standards Board issued FASB Interpretation No. 47 (FIN No. 47), “Accounting for Conditional Asset Retirement Obligations — an interpretation of FASB Statement No. 143.” FIN No. 47 clarifies that FASB Statement No. 143, “Accounting for Asset Retirement Obligations,” requires that an entity recognize a liability for the fair value of a conditional asset retirement obligation when incurred if the liability’s fair value can be reasonably estimated. FIN No. 47 is effective no later than the end of fiscal years ending after December 15, 2005. The adoption did not have a material impact on the Company’s consolidated financial statements.

In May 2005, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 154 (FAS No. 154), “Accounting Changes and Error Corrections.” This Statement replaces APB Opinion No. 20, “Accounting Changes” and FASB Statement No. 3, “Reporting Accounting Changes in Interim Financial Statements” and changes the requirements for the accounting for, and reporting of, a change in accounting principle. This Statement applies to all voluntary changes in accounting principle. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. When a pronouncement includes specific transition provisions, those provisions should be followed. The Statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The adoption did not have a material impact on the Company’s consolidated financial statements.

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 the Company’s 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.

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 and in Item 1A of Part 2 of this Form 10-Q. 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 first quarter of 2006, we achieved our highest quarterly levels for revenue, income from operations, net income and diluted earnings per share. Revenue was $222.5 million, income from operations was $54.4 million and net income was $32.2 million, or $0.40 diluted earnings per share. These results were achieved due primarily to strong performance from our well intervention, rental tools and marine segments, which more than offset the loss from operations incurred by our oil and gas segment.

In the well intervention segment, revenue was $102.1 million and income from operations was $19.7 million, a 15% and 105% increase, respectively, over the fourth quarter of 2005. A sharp increase in Gulf of Mexico activity was the primary driver of our improved performance as compared to the fourth quarter of 2005. Production-related work in the Gulf was higher as customers resumed projects that were deferred due to hurricane disruptions. In addition, many customers whose oil and gas properties suffered hurricane damage had completed their damage assessment and construction work, and began using our services to restore their production.

Demand for our plug and abandonment services also increased significantly. Many customers began plugging severely damaged wells and temporarily or permanently plugging other wells to lower their insurance exposure and risk of damage from any future hurricanes. In addition to providing services, we are also actively managing several hurricane recovery projects for customers through our well control subsidiary. Much of this work involves providing engineering services, including marine and well control engineering, supervision and execution.

In our rental tools segment, revenue was $77.8 million, a 14% increase as compared to the fourth quarter of 2005, and income from operations was $26.5 million, a 49% increase over the fourth quarter of 2005. Gulf of Mexico activity increased – particularly in the deepwater market area – which benefited rentals of drill pipe, stabilizers, drill collars, on-site accommodations, connecting iron and specialty tubulars.

In our marine segment, revenue was $30.2 million and income from operations was $13.1 million. These results were down slightly from the fourth quarter of 2005. Utilization was lower due to the number of liftboats that went through mandatory Coast Guard inspections, resulting in more shipyard days. As we typically expect lower demand for our liftboats and services during the winter months due to poor weather conditions, we typically schedule more inspections in the first quarter than any other quarter as we prepare our liftboats for the better weather conditions and demand of the summer season. We have not experienced the lower demand of the winter months in the first quarter of 2006 due to the necessary repair work needed as the result of the active hurricane season of 2005 and high commodity prices. Our average daily revenue increased slightly over the fourth quarter, reflecting higher dayrates. On March 1, 2006, we increased our dayrates for all liftboats by an average of approximately 20%, reflecting the strong demand we are experiencing.

Our oil and gas production was about 358,600 barrels of oil equivalent (boe) during the first quarter. Deferred production was about 235,000 boe. Our production that was shut-in from hurricane damage was off-line longer than we anticipated due to ongoing repairs to third-party pipelines. We also incurred about $1.9 million in additional hurricane-related expenses during the first quarter that are not expected to be recovered by insurance. As a result, the oil and gas segment recorded a $4.9 million loss from operations on revenue of $15.5 million. By mid-April, all of our production had resumed to levels experienced prior to Hurricanes Katrina and Rita.

Also in April, SPN Resources, LLC, acquired 16.2 billion cubic feet equivalent of net proved reserves (as of the December 1, 2005 effective date) from Explore Offshore, LLC, for $46.6 million in cash and the assumption of an estimated $3.7 million in decommissioning liabilities. The acquisition includes five leases located on the Outer Continental Shelf of the Gulf of Mexico encompassing four fields, nine structures, 13 operated wells and one well operated by a third party. Approximately 85% of the proved reserves are natural gas and 55% are proved developed reserves.

Comparison of the Results of Operations for the Three Months Ended March 31, 2006 and 2005

For the three months ended March 31, 2006, our revenues were $222.5 million, resulting in net income of $32.2 million or $0.40 diluted earnings per share. For the three months ended March 31, 2005, revenues were $173.2 million and net income was $17.2 million or $0.22 diluted earnings per share. We experienced significantly higher revenue and gross margin for our well intervention, rental tools and marine segments, which more than offset the loss from operations incurred by our oil and gas segment. While our well intervention, rental tools and marine segments experienced record high demand due to necessary repair work needed as the result of the active hurricane season of 2005 coupled with high commodity prices, our revenue and gross margin declined significantly for the oil and gas segment due to production that was shut-in as the result of damage from Hurricanes Katrina and Rita.

We typically experience lower demand for our services and rentals during the first quarter of the year due to the poor weather conditions of the winter months. We have not experienced the lower demand of the winter months in the first quarter of 2006 due to the necessary repair work needed as the result of the active hurricane season of 2005 and high commodity prices.

The following table compares our operating results for the three months ended March 31, 2006 and 2005. Gross margin is calculated by subtracting cost of services from revenue for each of our four business segments. Oil and gas eliminations represent products and services provided to the oil and gas segment by the Company’s other three segments.


	Revenue									Gross Margin
	2006			2005			Change			2006		%			2005		%			Change

Well Intervention	$	102,073		$	80,116		$	21,957		$	42,073		41	%	$	30,718		38	%	$	11,355
Rental Tools		77,774			52,627			25,147			53,476		69	%		35,093		67	%		18,383
Marine		30,207			19,798			10,409			18,194		60	%		7,868		40	%		10,326
Oil and Gas		15,471			25,955			(10,484	)		1,266		8	%		13,150		51	%		(11,884	)
Less: Oil and Gas Elim.		(3,056	)		(5,249	)		2,193			—		—			—		—			—

Total	$	222,469		$	173,247		$	49,222		$	115,009		52	%	$	86,829		50	%	$	28,180

The following discussion analyzes our results on a segment basis.

Well Intervention Segment

Revenue for our well intervention segment was $102.1 million for the three months ended March 31, 2006, as compared to $80.1 million for the same period in 2005. This segment’s gross margin percentage increased to 41% for the three months ended March 31, 2006 from 38% for the same period of 2005. We experienced higher revenue for most of our production-related services, especially well control, coiled tubing, hydraulic workover services, as production-related activity improved significantly in the Gulf of Mexico. In addition, revenue increased for our plug and abandonment services as many customers began plugging severely damaged wells and temporarily or permanently plugging 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 three months ended March 31, 2006 was $77.8 million, a 48% increase over the same period in 2005. The gross margin percentage slightly increased to 69% for the three months ended March 31, 2006 from 67% for the same period of 2005. We experienced significant increases in revenue from our on-site accommodations, drill pipe and accessories, specialty tubulars and stabilizers. The increases are primarily the result of significant increases in activity in the Gulf of Mexico particularly in our deepwater market area, as well as our international and domestic expansion efforts. Our international revenue for the rental tools segment has increased 50% to approximately $15.3 million for the quarter ended March 31, 2006 over the same period of 2005. Our biggest improvements were in the North Sea, Canada, Venezuela and Mexico.

Marine Segment

Our marine segment revenue for the three months ended March 31, 2006 increased 53% over the same period in 2005 to $30.2 million. The gross margin percentage for the three months ended March 31, 2006 increased to 60% from 40% for the same period in 2005. The three months ended March 31, 2006 were characterized by a significant increase in the demand for liftboats due to the construction and repair work needed as the result of the damage in the Gulf of Mexico from Hurricanes Katrina and Rita as well as significant increases in demand due to high oil and gas commodity prices. The fleet’s average dayrate increased over 100% to approximately $14,270 in the first quarter of 2006 from $6,950 in the first quarter of 2005. The fleet’s average utilization increased to approximately 85% for the first quarter of 2006 from 77% in the same period in 2005. The first quarter of 2005 also includes rental activity from the 105-foot and the 120 to 135-foot class liftboats, which were sold effective June 1, 2005.

Oil and Gas Segment

Oil and gas revenues were $15.5 million in the three months ended March 31, 2006, as compared to $26.0 million in the same period of 2005. The decrease in revenue is primarily the result of production which remained shut-in during the first quarter of 2006 following significant damage from Hurricanes Katrina and Rita. Our production was off-line longer than we anticipated due to ongoing repairs to third-party pipelines. In the first quarter of 2006, production was approximately 358,600 boe, as compared to approximately 600,500 boe in the first quarter of 2005. The gross margin percentage decreased to 8% in the three months ended March 31, 2006 from 51% in the same period of 2005 due to the shut-in production of the first quarter of 2006.

Depreciation, Depletion, Amortization and Accretion

Depreciation, depletion, amortization and accretion increased to $22.9 million in the three months ended March 31, 2006 from $22.4 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. This increase was offset by a decrease in depletion related to decreased production in our oil and gas properties.

General and Administrative Expenses

General and administrative expenses increased to $37.7 million for the three months ended March 31, 2006 from $32.4 million for the same period in 2005. This increase was primarily related to increased bonus accruals due to our improved performance; increased insurance costs; increased expenses related to our geographic expansion, oil and gas acquisitions and our growth; and increased expense from our new long-term incentive plan established late in the second quarter of 2005.

Liquidity and Capital Resources

In the three months ended March 31, 2006, we generated net cash from operating activities of $40.3 million as compared to $33.3 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 $68.6 million at March 31, 2006 compared to $54.5 million at December 31, 2005.

We made $44.5 million of capital expenditures during the three months ended March 31, 2006, of which approximately $18.4 million was used to expand and maintain our rental tool equipment inventory. We also made $10.4 million of capital expenditures in our oil and gas segment and $14.0 million of capital expenditures to expand and maintain the asset base of our well intervention and marine segments, including $5.3 million of the remaining purchase price of the anchor handling tug and $1.4 million of progress payments on the crane. In addition, we made $1.7 million of capital expenditures on construction and improvements to our facilities.

We have contracted to construct an 880-ton derrick barge to support decommissioning and construction operations. The contracts are for the construction of a 328-foot barge and crane for a price of approximately $23 million. This amount does not include any future change orders, barge outfitting or mobilization costs. Progress payments are made on the crane in accordance with the terms set forth in the contract. Letters of credit are due on the barge based on contract milestones. The contract price for the barge will be payable upon its delivery and acceptance. We expect to take delivery of the barge late in the second quarter or early in the third quarter of 2006. We intend to utilize it for construction or removal projects in either international or Gulf of Mexico market areas and, during lower demand periods, to remove platforms and structures owned by our subsidiary, SPN Resources, LLC. At March 31, 2006, the total amount of progress payments made on the crane was approximately $8.1 million. We also purchased an anchor handling tug for the barge for approximately $5.9 million. The tug is currently under a bareboat charter in Asia.

We currently believe that we will make approximately $160 to $170 million of capital expenditures, excluding acquisitions and targeted asset purchases, during the remaining nine months of 2006 primarily to purchase the derrick barge, further expand our rental tool asset base and perform workovers on SPN Resources oil and gas properties. We believe that our current working capital, cash generated from our operations and availability under our revolving credit facility will provide sufficient funds for our identified capital projects.

We have a bank credit facility consisting of a $150 million revolving credit facility, with an option to increase it to $250 million. Any balance outstanding on the revolving credit facility is due on October 31, 2008. At March 31, 2006, we had no balance on this bank credit facility, but we had approximately $20.2 million of letters of credit outstanding, which reduce the borrowing availability under this credit facility. The credit facility bears interest at a LIBOR rate plus margins that depend on our leverage ratio. As of May 8, 2006, we had $6.0 million outstanding on this facility, and the weighted average interest rate was 7.9%. Indebtedness under the credit facility is secured by substantially all of our assets, including the pledge of the stock of our principal subsidiaries. The credit facility contains customary events of default and requires that we satisfy various financial covenants. It also limits our capital expenditures, our ability to pay dividends or make other distributions, make acquisitions, make changes to our capital structure, create liens, incur additional indebtedness or assume additional decommissioning liabilities.

We have $17.4 million outstanding at March 31, 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.

We also have outstanding $200 million of 8 7/8% senior notes due 2011. The indenture governing the senior notes requires semi-annual interest payments on every May 15^th and November 15^th through the maturity date of May 15, 2011. The indenture governing the senior notes contains certain covenants that, among other things, prevent us from incurring additional debt, paying dividends or making other distributions, unless our ratio of cash flow to interest expense is at least 2.25 to 1, except that we may incur debt in addition to the senior notes in an amount equal to 30% of our net tangible assets, which was approximately $220 million at March 31, 2006. The indenture also contains covenants that restrict our ability to create certain liens, sell assets or enter into certain mergers or acquisitions.

On May 5, 2006, we announced that we have commenced a tender offer for all of our outstanding senior notes. In conjunction with the tender offer, we are also soliciting 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. The cash consideration for the tender offer is $1,045.63 per $1,000 in aggregate principal amount of senior notes tendered. After the expiration of the tender offer, we intend to redeem any outstanding senior notes at the redemption price of 104.438% of the principal amount redeemed.

We intend to obtain new financing through the issuance of up to $300,000,000 new unsecured senior notes, the proceeds of which will be used to fund the purchase price of the tender offer, to redeem any senior notes not purchased in the tender offer and to provide additional working capital. The tender offer is conditioned on, among other things, receipt of consents from holders of a majority of the outstanding principal amount of senior notes, our completion of the issuance of the new unsecured senior notes on the terms and conditions acceptable to us, and the amendment of the terms of the bank credit facility to allow for the issuance of the new unsecured senior notes. Subject to the satisfaction of all the terms and conditions, we currently expect to complete the tender offer in late May 2006. Upon completion of this transaction, we expect to recognize a loss from the early extinguishment of long-term debt of approximately $12 to $13 million.

The following table summarizes our contractual cash obligations and commercial commitments at March 31, 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 $30.2 million, when decommissioning operations are performed. We do not have any other material obligations or commitments.


	Remaining
	Nine
	Months
Description	2006		2007		2008		2009		2010		2011		Thereafter

Long-term debt, including estimated interest payments	$	19,670	$	19,617	$	19,565	$	19,513	$	19,461	$	210,533	$	19,015
Decommissioning liabilities		9,815		24,565		5,480		2,146		9,929		28,122		35,712
Operating leases		4,295		4,479		2,203		1,021		509		173		11,971
Derrick barge construction		14,576		—		—		—		—		—		—


Total	$	48,356	$	48,661	$	27,248	$	22,680	$	29,899	$	238,828	$	66,698

We have no off-balance sheet arrangements other than our potential additional consideration that may be payable as a result of the future operating performances of our acquisitions. At March 31, 2006, the maximum additional consideration payable for our prior acquisitions was approximately $2.4 million. These amounts are not classified as liabilities under generally accepted accounting principles and are not reflected in our financial statements until the amounts are fixed and determinable. When amounts are determined, they are capitalized as part of the purchase price of the related acquisition. We do not have any other financing arrangements that are not required under generally accepted accounting principles to be reflected in our financial statements.

We 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 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 our results of operations or our financial position.

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. As of March 31, 2006, we had the following contracts in place:


Crude Oil Positions
	Instrument	Strike	Volume (Bbls)
Remaining Contract Term	Type	Price (Bbl)	Daily	Total (Bbls)
4/06 - 8/06	Swap	$39.45	1,000	184,000
4/06 - 8/06	Collar	$35.00/$45.60	1,000	184,000

Our hedged volume as of March 31, 2006 was approximately 49% of our estimated production from proved reserves for the balance of the terms of the contracts. Had these contracts been terminated at March 31, 2006, the estimated loss would have been $5.7 million, net of taxes.

We used a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of crude oil would have on the fair value of our existing derivative instruments. Based on the derivative instruments outstanding at March 31, 2006, a 10% increase in the underlying commodity price, would increase the estimated loss associated with the commodity derivative instrument by $1.3 million, net of taxes.

Interest Rate Risk

At March 31, 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.

PART II. OTHER INFORMATION

Item 1A. Risk Factors

There have been no material changes from the risk factors as previously disclosed in Item 1A of Part I of our Form 10-K for the year ended December 31, 2005 except as updated below:

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

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

	•		fires;

	•		explosions, blowouts, and cratering;

	•		well blowouts;

	•		hurricanes and other extreme weather conditions;

	•		mechanical problems, including pipe failure;

	•		abnormally pressured formations; and

	•		environmental accidents, including oil spills, gas leaks or ruptures, uncontrollable flows of oil, gas, brine or well fluids, or other discharges of toxic gases or other pollutants.

Our liftboats are also subject to operating risks such as catastrophic marine disaster, adverse weather conditions, collisions and navigation errors.

The occurrence of these risks could result in substantial losses due to personal injury, loss of life, damage to or destruction of wells, production facilities or other property or equipment, or damages to the environment. In addition, certain of our employees who perform services on offshore platforms and marine vessels are covered by provisions of the Jones Act, the Death on the High Seas Act and general maritime law. These laws make the liability limits established by federal and state workers’ compensation laws inapplicable to these employees and instead permit them or their representatives to pursue actions against us for damages for job-related injuries. In such actions, there is generally no limitation on our potential liability.

Any litigation arising from a catastrophic occurrence involving our services, equipment or oil and gas production operations could result in large claims for damages. The frequency and severity of such incidents affect our operating costs, insurability and relationships with customers, employees and regulators. Any increase in the frequency or severity of such incidents, or the general level of compensation awards with respect to such incidents, could affect our ability to obtain projects from oil and gas companies or insurance. We maintain several types of insurance to cover liabilities arising from our services, including onshore and offshore non-marine operations, as well as marine vessel operations. These policies include primary and excess umbrella liability policies with limits of $50 million per occurrence, including sudden and accidental pollution incidents. We also maintain property insurance on our physical assets, including marine vessels, and operating equipment. Successful claims for which we are not fully insured may adversely affect our working capital and profitability.

For our oil and gas operations, we maintain control of well, operators extra expense and pollution liability coverage, to include our liabilities under the federal Oil Pollution Act of 1990, or OPA. Limits maintained for these operations are $50 million per occurrence for well control incidents unrelated to windstorm, and $35 million in the aggregate for windstorm related events. The liability limit is $50 million per occurrence for non-well control events. We also maintain property insurance on our physical assets, including offshore production facilities, pipelines and operating equipment. As a result of the losses caused by recent hurricanes in the Gulf of Mexico, we experienced very substantial increases in our costs of insurance, as well as increased deductibles and self-insured retentions. Our offshore property insurance coverage is subject to an annual loss limit of $35 million in the aggregate with respect to property damage and well control events caused by hurricanes and named storms. We are seeking alternatives to allow us to increase this annual aggregate limit. Any significant uninsured losses could have a material adverse effect on our financial position, results of operations and cash flows.

The cost of many of the types of insurance coverage maintained by us has increased significantly during recent years and resulted in the retention of additional risk by us, primarily through higher insurance deductibles. Very few

insurance underwriters offer certain types of insurance coverage maintained by us, and there can be no assurance that any particular type of insurance coverage will continue to be available in the future, that we will not accept retention of additional risk through higher insurance deductibles or otherwise, or that we will be able to purchase our desired level of insurance coverage at commercially feasible rates. Further, due to the losses as a result of hurricanes that occurred in the Gulf of Mexico in 2005 and 2004, we were not able to obtain insurance coverage comparable with that of prior years, thus putting us at a greater risk of loss due to severe weather conditions. In addition, we are experiencing increased costs for available insurance coverage which also impose higher deductibles and limit maximum aggregate recoveries for certain perils such as hurricane related windstorm damage or loss. As a result, we have been forced to modify our risk management program in response to changes in the insurance market, including increased risk retention. Any significant uninsured losses could have a material adverse effect on our financial position, results of operations and cash flows.

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

	•		the presence of unanticipated pressure or irregularities in formations;

	•		equipment failures or accidents;

	•		adverse weather conditions;

	•		compliance with governmental requirements; and

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

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.

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:	May 9, 2006	By:	/s/ Robert S. Taylor

				Robert S. Taylor
				Executive Vice President, Treasurer and Chief Financial Officer
				(Principal Financial and Accounting Officer)

EXHIBIT INDEX


3.1		Certificate of Incorporation of the Company (incorporated herein by reference to the Company’s Quarterly Report on Form 10-QSB for the quarter ended March 31, 1996).

3.2		Certificate of Amendment to the Company’s Certificate of Incorporation (incorporated herein by reference to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999).

3.3		Amended and Restated Bylaws of the Company (incorporated herein by reference to Exhibit 3.1 to the Company’s Form 8-K filed on November 15, 2004).

31.1		Officer’s certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Officer’s certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1		Officer’s certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Officer’s certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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