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

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

Commission File No. 001-34037

SUPERIOR ENERGY SERVICES, INC.

Delaware		75-2379388
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)
601 Poydras, Suite 2400
New Orleans, Louisiana		70130
(Address of principal executive offices)		(Zip Code)

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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

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

Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company o

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

The number of shares of the registrant’s common stock outstanding on November 1, 2010 was 78,814,897.

 

 

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Quarterly Report on Form 10-Q for
the Quarterly Period Ended September 30, 2010

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			24
Item 3. Quantitative and Qualitative Disclosures about Market Risk			33
Item 4. Controls and Procedures			34
PART II. OTHER INFORMATION
Item 1A. Risk Factors			35
Item 6. Exhibits			38
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidated Balance Sheets
September 30, 2010 and December 31, 2009
(in thousands, except share data)

		9/30/2010				12/31/2009
		(unaudited)				(audited)
ASSETS
Current assets:
Cash and cash equivalents		$	47,381			$	206,505
Accounts receivable, net of allowance for doubtful accounts of $23,458 and $23,679 at September 30, 2010 and December 31, 2009, respectively			494,283				337,151
Income taxes receivable			—				12,674
Prepaid expenses			27,765				20,209
Other current assets			200,750				287,024
Total current assets			770,179				863,563
Property, plant and equipment, net of accumulated depreciation and depletion of $730,328 and $591,479 at September 30, 2010 and December 31, 2009, respectively			1,349,396				1,058,976
Goodwill			576,774				482,480
Notes receivable			84,965				—
Equity-method investments			61,812				60,677
Intangible and other long-term assets, net of accumulated amortization of $20,329 and $15,248 at September 30, 2010 and December 31, 2009, respectively			99,309				50,969
Total assets		$	2,942,435			$	2,516,665
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	82,708			$	63,466
Accrued expenses			180,620				133,602
Income taxes payable			24,386				—
Deferred income taxes			29,704				30,501
Current portion of decommissioning liabilities			25,804				—
Current maturities of long-term debt			810				810
Total current liabilities			344,032				228,379
Deferred income taxes			218,904				209,053
Decommissioning liabilities			116,116				—
Long-term debt, net			879,495				848,665
Other long-term liabilities			116,413				52,523
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 78,814,777 shares at September 30, 2010 and 78,559,350 shares at December 31, 2009			79				79
Additional paid in capital			400,632				387,885
Accumulated other comprehensive loss, net			(21,121	)			(18,996	)
Retained earnings			887,885				809,077
Total stockholders’ equity			1,267,475				1,178,045
Total liabilities and stockholders’ equity		$	2,942,435			$	2,516,665

See accompanying notes to consolidated financial statements.

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidated Statements of Operations
Three and Nine Months Ended September 30, 2010 and 2009
(in thousands, except per share data)
(unaudited)

		Three Months								Nine Months
		2010				2009				2010				2009
Revenues		$	435,353			$	386,455			$	1,224,720			$	1,184,725
Costs and expenses:
Cost of services (exclusive of items shown separately below)			232,308				215,674				661,276				635,407
Depreciation, depletion, amortization and accretion			56,805				52,720				162,152				153,566
General and administrative expenses			84,912				63,425				248,165				188,694
Reduction in value of assets			—				—				—				92,683
Total costs and expenses			374,025				331,819				1,071,593				1,070,350
Income from operations			61,328				54,636				153,127				114,375
Other income (expense):
Interest expense, net			(12,456	)			(12,320	)			(39,174	)			(37,328	)
Earnings (losses) from equity-method investments, net			3,030				(4,161	)			9,185				(21,331	)
Reduction in value of equity-method investment			—				—				—				(36,486	)
Income before income taxes			51,902				38,155				123,138				19,230
Income taxes			18,685				13,736				44,330				6,923
Net income		$	33,217			$	24,419			$	78,808			$	12,307
Basic earnings per share		$	0.42			$	0.31			$	1.00			$	0.16
Diluted earnings per share		$	0.42			$	0.31			$	0.99			$	0.16
Weighted average common shares used in computing earnings per share:
Basic			78,797				78,188				78,683				78,126
Incremental common shares from stock-based compensation			925				624				890				558
Diluted			79,722				78,812				79,573				78,684

See accompanying notes to consolidated financial statements.

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidated Statements of Cash Flows
Nine Months Ended September 30, 2010 and 2009
(in thousands)
(unaudited)

		2010				2009
Cash flows from operating activities:
Net income		$	78,808			$	12,307
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion			162,152				153,566
Deferred income taxes			1,087				26,302
Reduction in value of assets			—				92,683
Reduction in value of equity-method investment			—				36,486
Stock-based and performance share unit compensation expense, net			11,952				6,339
Retirement and deferred compensation plans expense, net			5,035				1,154
Earnings / losses from equity-method investments, net of cash received			416				24,737
Amortization of debt acquisition costs and note discount			17,857				16,037
Other, net			(3,743	)			—
Changes in operating assets and liabilities, net of acquisitions and dispositions:
Receivables			(131,504	)			7,620
Other current assets			118,619				(155,715	)
Accounts payable			(1,547	)			(18,295	)
Accrued expenses			28,105				(8,617	)
Income taxes			36,482				(29,670	)
Other, net			13,031				12,012
Net cash provided by operating activities			336,750				176,946
Cash flows from investing activities:
Payments for capital expenditures			(238,812	)			(241,623	)
Acquisitions of businesses, net of cash acquired			(262,048	)			—
Other, net			(6,269	)			(3,721	)
Net cash used in investing activities			(507,129	)			(245,344	)
Cash flows from financing activities:
Net borrowings from revolving credit facility			16,500				57,200
Principal payments on long-term debt			(405	)			(405	)
Payment of debt acquisition costs			(5,164	)			(2,308	)
Proceeds from exercise of stock options			396				306
Tax benefit from exercise of stock options			195				127
Proceeds from issuance of stock through employee benefit plans			1,505				1,615
Other			(2,100	)			—
Net cash provided by financing activities			10,927				56,535
Effect of exchange rate changes on cash			328				1,292
Net decrease in cash and cash equivalents			(159,124	)			(10,571	)
Cash and cash equivalents at beginning of period			206,505				44,853
Cash and cash equivalents at end of period		$	47,381			$	34,282

See accompanying notes to consolidated financial statements.

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Notes to Unaudited Condensed Consolidated Financial Statements
Nine Months Ended September 30, 2010

(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 notes should be read in conjunction with the consolidated financial statements and notes thereto included in Superior Energy Services, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2009 and Management’s Discussion and Analysis of Financial Condition and Results of Operations herein.

The financial information of Superior Energy Services, Inc. and subsidiaries (the Company) for the three and nine months ended September 30, 2010 and 2009 has not been audited. However, in the opinion of management, all 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 2010 presentation.

(2) Acquisitions

Superior Completion Services

On August 30, 2010, the Company acquired certain assets (now operating as Superior Completion Services) from subsidiaries of Baker Hughes Incorporated (Baker Hughes) for approximately $54.3 million. The assets purchased were used in Baker Hughes’ Gulf of Mexico stimulation and sand control business. Superior Completion Services provides the Company greater exposure to well completions and intervention projects earlier in the life cycle of the well.

The following table summarizes the consideration paid for Superior Completion Services and the fair value of the assets acquired and liabilities assumed at the acquisition date (in thousands):

Current assets		$	28,911
Property, plant and equipment			34,222
Identifiable intangible assets			1,495
Current liabilities			(352	)
Decommissioning liabilities			(10,000	)
Total consideration paid		$	54,276

Current assets include inventory consisting of sand control completion tools (see note 5). Identifiable intangible assets include amortizable intangibles of brand names related to well completion tools and services with a useful life of 8 years. Decommissioning liabilities consist of contractual obligations to restore two chartered stimulation vessels to their original condition prior to returning to their respective owners (see note 10).

The Company expensed a total of approximately $0.2 million of acquisition-related costs during the nine month period ended September 30, 2010, which was recorded as general and administrative expenses in the condensed consolidated statements of operations. The fair value of the assets acquired and liabilities assumed is provisional pending receipt of final third party valuations.

Hallin

On January 26, 2010, the Company acquired 100% of the equity interest of Hallin Marine Subsea International Plc (Hallin) for approximately $162.3 million of cash. Additionally, the Company repaid approximately $55.5 million of Hallin’s debt. Hallin is an international provider of integrated subsea services and engineering solutions, focused on installing, maintaining and extending the life of subsea wells. Hallin operates in international offshore oil and gas markets with offices and facilities located in Singapore, Indonesia, Australia, Scotland and the United States. The acquisition of Hallin provides the Company the opportunity to enhance its position in the subsea and well enhancement market through Hallin’s existing subsea assets (remotely operated vehicles, saturation diving systems, chartered and owned vessels) and newbuild vessel program.

The following table summarizes the consideration paid for Hallin and the fair value of the assets acquired and liabilities assumed at the acquisition date (in thousands):

Current assets		$	42,096
Property, plant and equipment			147,721
Equity-method investments			1,299
Identifiable intangible assets			118,150
Current liabilities			(30,217	)
Deferred income taxes			(8,130	)
Other long term liabilities			(53,159	)
Total consideration paid		$	217,760

Identifiable intangible assets include goodwill of $93.7 million and amortizable intangibles of $24.5 million. Goodwill consists of assembled workforce, entry into new international markets and business lines, as well as synergistic opportunities created by including the operations of Hallin with the existing services of the Company. All of the goodwill was assigned to the Company’s subsea and well enhancement segment. None of the goodwill recognized is expected to be deductible for income tax purposes. Amortizable intangibles consist of tradenames and customer relationships that have a weighted average useful life of 18 years.

The fair value of the current assets acquired includes trade receivables with a fair value of $19.3 million. The gross amount due from customers is $21.4 million, of which $2.1 million is deemed to be doubtful.

The Company expensed a total of $0.6 million of acquisition-related costs during the nine month period ended September 30, 2010, which was recorded as general and administrative expenses in the condensed consolidated statements of operations. An additional $4.9 million of acquisition-related costs, a portion of which was related to foreign currency exchange loss, was expensed in the year ended December 31, 2009.

Hallin is the lessee of a dynamically positioned subsea vessel under a capital lease expiring in 2019 with a 2 year renewal option. Hallin owns a 5% equity interest in the entity that owns this leased asset. The entity owning this vessel had $33.7 million of debt as of December 31, 2009, all of which was non-recourse to the Company. The amount of the asset and liability under this capital lease is recorded at the present value of the lease payments. This vessel is depreciated using the units-of-production method based on the utilization of the vessel and is subject to a minimum amount of annual depreciation. The units-of-production method is used for this vessel because depreciation occurs primarily through use rather than through the passage of time. Depreciation expense for this asset under the capital lease was approximately $2.2 million from the date of acquisition through September 30, 2010, and $1.3 million for the three month period ended September 30, 2010. Included in other long-term liabilities at September 30, 2010 is $34.4 million related to the obligations under this capital lease.

Additionally, the Company has provisionally estimated certain tax liabilities related to this acquisition; however, due to the large number of jurisdictions, the complexity of tax laws and the pending tax filings, the Company continues to evaluate these liabilities.

Bullwinkle Platform

On January 31, 2010, Wild Well Control, Inc. (Wild Well), a wholly-owned subsidiary of the Company, acquired 100% ownership of Shell Offshore Inc.’s Gulf of Mexico Bullwinkle platform and its related assets, including 29 wells, and assumed the decommissioning obligation for such assets. Immediately after Wild Well acquired these assets, it conveyed an undivided 49% interest in these assets and the related well plugging and abandonment obligations to Dynamic Offshore Resources, LLC (Dynamic Offshore), which operates these assets. Additionally, Dynamic Offshore will pay Wild Well to extinguish its 49% portion of the well plugging and abandonment obligation (see note 3). In addition to the revenue generated from oil and gas production, the platform also generates revenue from several production handling arrangements for other subsea fields. At the end of their respective economic lives, Wild Well will plug and abandon the wells and decommission the Bullwinkle platform. This body of work will provide additional opportunities for our products and services in the Gulf of Mexico, especially during cyclical and seasonal slower periods.

The following table summarizes the fair value of the assets acquired and liabilities assumed as of the acquisition date (in thousands):

Current assets		$	3,641
Notes receivable			81,465
Property, plant and equipment			41,453
Decommissioning liabilities			(126,559	)
Total consideration paid		$	—

Notes receivable consist of a commitment from the seller of the oil and gas properties to pay Wild Well upon the decommissioning of the platform. These notes are recorded at present value, and the related discount is amortized to interest income based on the expected timing of the platform’s removal.

The Company expensed a total of $0.1 million of acquisition-related costs during the nine month period ended September 30, 2010, which was recorded as general and administrative expenses in the condensed consolidated statements of operations.

The revenue and earnings (losses) related to Superior Completion Services, Hallin and the Bullwinkle platform included in the Company’s condensed consolidated statement of operations for the nine month period ended September 30, 2010, and the revenue and earnings of the Company on a consolidated basis as if these acquisitions had occurred on January 1, 2010, or January 1, 2009, with pro forma adjustments to give effect to depreciation and certain other adjustments, together with related income tax effects, are as follows (in thousands, except per share amounts):

										Basic				Diluted
										earnings				earnings
		Revenue				Net income				per share				per share
Actual from date of acquisition through the period ended September 30, 2010		$	117,210			$	10,720			$	0.14			$	0.13
Supplemental pro forma for the Company:
Three months ended September 30, 2010		$	440,378			$	29,772			$	0.38			$	0.37
Nine months ended September 30, 2010		$	1,278,341			$	70,847			$	0.90			$	0.89
Three months ended September 30, 2009		$	439,950			$	29,995			$	0.38			$	0.38
Nine months ended September 30, 2009		$	1,353,293			$	29,632			$	0.38			$	0.38

The Company has no off-balance sheet financing arrangements other than potential additional consideration that may be payable as a result of future operating performances of certain acquisitions. At September 30, 2010, the maximum additional consideration payable for these acquisitions was approximately $18.0 million and will be determined and payable through 2012. Since these acquisitions occurred before the Company adopted the revised

authoritative guidance for business combinations, these amounts are not classified as liabilities and are not reflected in the Company’s condensed consolidated financial statements until the amounts are fixed and determinable. When these amounts are determined, they will be capitalized as part of the purchase price of the related acquisition. In the nine months ended September 30, 2010, the Company paid additional consideration of approximately $1.3 million as a result of prior acquisitions.

(3) Long-Term Contracts

In January 2010, Wild Well acquired 100% ownership of Shell Offshore Inc.’s Gulf of Mexico Bullwinkle platform and its related assets, and assumed the decommissioning obligations of such assets. In connection with the conveyance of an undivided 49% interest in these assets and the related well plugging and abandonment obligations, Dynamic Offshore will pay Wild Well to extinguish its portion of the well plugging and abandonment obligations, limited to the current fair value of the obligation at the time of acquisition. As part of the asset purchase agreement with Shell Offshore Inc., Wild Well was required to obtain a $50 million performance bond as well as fund $50 million into an escrow account. This escrow account will be funded $3.0 million monthly through May 2011, with a final payment of $2.0 million in June 2011. Dynamic Offshore will fund a portion of this amount as part of its payment obligation for the well plugging and abandonment. Included in intangible and other long-term assets, net is escrowed cash of $24.0 million as of September 30, 2010. Included in other long-term liabilities is deferred revenue of $11.8 million as of September 30, 2010 (see note 2).

In connection with the sale of 75% of its interest in SPN Resources, LLC (SPN Resources) in 2008, the Company retained preferential rights on certain service work and entered into a turnkey contract to perform well abandonment and decommissioning work associated with oil and gas properties owned and operated by SPN Resources. This contract covers only routine end of life well abandonment, pipeline and platform decommissioning for properties owned and operated by SPN Resources at the date of closing and has a remaining fixed price of approximately $134.8 million as of September 30, 2010. The turnkey contract consists of numerous, separate billable jobs estimated to be performed through 2022. Each job is short-term in duration and is individually recorded on the percentage-of-completion method utilizing costs incurred as a percentage of total estimated costs.

In December 2007, Wild Well entered into contractual arrangements pursuant to which it is decommissioning seven downed oil and gas platforms and related well facilities located offshore in the Gulf of Mexico for a fixed sum of $750 million, which is payable in installments upon the completion of specified portions of work. The contract contains certain covenants primarily related to Wild Well’s performance of the work. As of September 30, 2010, all work was complete, pending certain regulatory approvals. The revenue related to the contract for decommissioning these downed platforms and well facilities is recorded on the percentage-of-completion method utilizing costs incurred as a percentage of total estimated costs. Included in other current assets is $109.9 million and $209.5 million at September 30, 2010 and December 31, 2009, respectively, of costs and estimated earnings in excess of billings related to this contract.

(4) Stock-Based Compensation and Retirement Plans

The Company maintains various stock incentive plans that provide long-term incentives to the Company’s key employees, including officers and directors, consultants and advisors (Eligible Participants). Under the incentive plans, 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. In connection with the transition of executive management in the second quarter of 2010, the Company issued approximately 1 million non-qualified stock options, approximately 177,000 shares of restricted stock and 30,000 performance share units. Additionally, vesting of certain grants has been accelerated to coincide with the terms of associated change in executive management.

Stock Options

The Company has issued 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. The Company’s compensation expense related to stock options for the nine months ended September 30, 2010 and 2009 was approximately $4.7 million and $1.8 million, respectively, which is reflected in general and administrative expenses.

Restricted Stock

The Company has issued shares of restricted stock under its stock incentive plans. Shares of restricted stock generally vest in equal annual installments over three years. Non-vested shares are generally forfeited upon the termination of employment. Holders of shares of restricted stock are entitled to all rights of a stockholder of the Company with respect to the restricted stock, including the right to vote the shares and receive any dividends or other distributions. The Company’s compensation expense related to shares of outstanding restricted stock for the nine months ended September 30, 2010 and 2009 was approximately $5.8 million and $4.4 million, respectively, which is reflected in general and administrative expenses.

Restricted Stock Units

The Company has issued restricted stock units (RSUs) to its non-employee directors under its stock incentive plans. Annually, each non-employee director is issued a number of RSUs having an aggregate dollar value determined by the Company’s Board of Directors. An RSU represents the right to receive from the Company, within 30 days of the date the director ceases to serve on the Board, one share of the Company’s common stock. The Company’s expense related to RSUs for the nine months ended September 30, 2010 and 2009 was approximately $1.0 million and $0.5 million, respectively, which is reflected in general and administrative expenses.

Performance Share Units

The Company has issued performance share units (PSUs) to its employees as part of the Company’s long-term incentive program. There is a three year performance period associated with each PSU grant. The two performance measures applicable to all participants are the Company’s return on invested capital and total stockholder return relative to those of the Company’s pre-defined “peer group.” If the participant has met specified continued service requirements, the PSUs will settle in cash or a combination of cash and up to 50% of equivalent value in the Company’s common stock, at the discretion of the compensation committee. The Company’s compensation expense related to all outstanding PSUs for the nine months ended September 30, 2010 and 2009 was approximately $6.6 million and $4.1 million, respectively, which is reflected in general and administrative expenses. The Company has recorded a current liability of approximately $6.6 million and $6.4 million at September 30, 2010 and December 31, 2009, respectively, for outstanding PSUs, which is reflected in accrued expenses. Additionally, the Company has recorded a long-term liability of approximately $7.9 million and $7.8 million at September 30, 2010 and December 31, 2009, respectively, for outstanding PSUs, which is reflected in other long-term liabilities. During the nine month period ended September 30, 2010, the Company paid approximately $6.4 million to its employees to settle PSUs for the performance period ended December 31, 2009. During the nine month period ended September 30, 2009, the Company paid approximately $4.7 million and issued approximately 71,400 shares of its common stock to its employees to settle PSUs for the performance period ended December 31, 2008.

Employee Stock Purchase Plans

The Company has employee stock purchase plans under which an aggregate of 1,250,000 shares of common stock were reserved for issuance. Under these stock purchase plans, eligible employees can purchase shares of the Company’s common stock at a discount. The Company received $1.5 million and $1.6 million related to shares issued under these plans for the nine month periods ended September 30, 2010 and 2009, respectively. For each nine month period ended September 30, 2010 and 2009, the Company recorded compensation expense of approximately $0.3 million, which is reflected in general and administrative expenses. Additionally, the Company issued approximately 80,000 shares and 115,300 shares in the nine month periods ended September 30, 2010 and 2009, respectively, related to these stock purchase plans.

Deferred Compensation Plan

The Company has a non-qualified deferred compensation plan which allows certain highly compensated employees to defer up to 75% of their base salary, up to 100% of their bonus, and up to 100% of the cash portion of their PSU compensation to the plan. Payments are made to participants based on their annual enrollment elections and plan balance. Participants earn a return on their deferred compensation that is based on hypothetical investments in certain mutual funds. Changes in market value of these hypothetical participant investments are reflected as an adjustment to the deferred compensation liability of the Company with an offset to compensation expense (see note 15).

Supplemental Executive Retirement Plan

The Company has a supplemental executive retirement plan (SERP). The SERP provides retirement benefits to the Company’s executive officers and certain other designated key employees. The SERP is an unfunded, non-qualified defined contribution retirement plan, and all contributions under the plan are unfunded credits to a notional account maintained for each participant. Under the SERP, the Company will generally make annual contributions to a retirement account based on age and years of service. The Company may also make discretionary contributions to a participant’s account. The Company recorded compensation expense of $5.4 million, inclusive of a discretionary contribution to the account of its chief operating officer in the amount of $4.7 million as part of its executive management transition, and $1.6 million in general and administrative expenses for the nine month periods ended September 30, 2010 and 2009, respectively.

(5) Other Current Assets

Other current assets include approximately $110.6 million and $210.0 million of costs incurred and estimated earnings in excess of billings on uncompleted contracts at September 30, 2010 and December 31, 2009, respectively. The Company follows the percentage-of-completion method of accounting for applicable contracts. Accordingly, income is recognized in the ratio that costs incurred bears to estimated total costs. Adjustments to cost estimates are made periodically, and losses expected to be incurred on contracts in progress are charged to operations in the period such losses are determined.

Additionally, other current assets include approximately $32.3 million and $2.9 million of inventory at September 30, 2010 and December 31, 2009, respectively. Inventory consists primarily of finished goods. The increase in inventory is primarily related to the acquisition of Superior Completion Services (see note 2).

(6) 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 (losses) from equity-method investments on its condensed consolidated statements of operations.

The Company’s equity-method investment balance in SPN Resources was approximately $47.8 million at September 30, 2010 and $52.3 million at December 31, 2009. The Company recorded earnings from its equity-method investment in SPN Resources of approximately $3.9 million for the nine months ended September 30, 2010. For the nine months ended September 30, 2009, the company recorded losses from its equity-method investment in SPN Resources of approximately $7.3 million. Additionally, the Company received approximately $8.4 million and $3.3 million of cash distributions from its equity-method investment in SPN Resources for the nine month periods ended September 30, 2010 and 2009. The Company, where possible and at competitive rates, provides its products and services to assist SPN Resources in producing and developing its oil and gas properties. The Company had a receivable from SPN Resources of approximately $4.1 million at September 30, 2010 and approximately $1.9 million at December 31, 2009. The Company also recorded revenue from SPN Resources of approximately $11.1 million and $10.9 million for the nine months ended September 30, 2010 and 2009, respectively.

During the second quarter of 2009, the Company wrote off the remaining carrying value of its 40% interest in Beryl Oil and Gas L.P. (BOG), $36.5 million, and suspended recording its share of BOG’s operating results under equity-method accounting as a result of continued negative BOG operating results, lack of viable interested buyers and

unsuccessful attempts to renegotiate the terms and conditions of its loan agreements with lenders on terms that would preserve the Company’s investment. The Company’s total cash contribution for this equity-method investment in BOG was approximately $57.8 million. During the nine months ended September 30, 2009, the Company recorded losses from its equity-method investment in BOG of approximately $14.0 million. The Company also recorded revenue of approximately $6.1 million from BOG for the nine months ended September 30, 2009.

In October 2009, DBH, LLC (DBH) acquired BOG in connection with a restructuring of BOG in which the previously existing debt obligations of BOG were partially extinguished and otherwise renegotiated. Simultaneous with that acquisition, the Company acquired a 24.6% membership interest in DBH for approximately $8.7 million. The Company’s equity-method investment balance in DBH was approximately $11.8 million at September 30, 2010 and $7.7 million at December 31, 2009. During the nine months ended September 30, 2010, the Company recorded earnings from its equity-method investment in DBH of approximately $5.1 million. Additionally, the Company received $1.0 million of cash distributions from its equity-method investment in DBH for the nine month period ended September 30, 2010. The Company, where possible and at competitive rates, provides its products and services to assist DBH in producing and developing its oil and gas properties. The Company had a receivable from DBH of approximately $0.9 million at September 30, 2010 and approximately $2.3 million at December 31, 2009. The Company also recorded revenue of approximately $2.5 million from DBH for the nine months ended September 30, 2010.

The Company also holds investments in other entities that are accounted for under the equity-method totaling $2.2 million at September 30, 2010 and $0.7 million at December 31, 2009.

Combined summarized financial information for all investments that are accounted for using the equity-method of accounting is as follows (in thousands):

		September 30,				December 31
		2010				2009
Current Assets		$	131,433			$	162,870
Noncurrent assets			532,492				500,187
Total assets		$	663,925			$	663,057
Current liabilities		$	60,239			$	81,675
Noncurrent liabilities			215,374				218,003
Total liabilities		$	275,613			$	299,678
		Three Months Ended September 30,								Nine Months Ended September 30,
		2010				2009				2010				2009
Revenues		$	50,171			$	68,037			$	154,712			$	192,056
Cost of sales			17,819				28,290				63,187				84,792
Gross profit		$	32,352			$	39,747			$	91,525			$	107,264
Income (loss) from continuing operations		$	11,400			$	(5,159	)		$	27,546			$	(14,702	)
Net income (loss)		$	238			$	(24,350	)		$	27,473			$	(73,374	)

(7) Debt

The Company has a $400 million bank revolving credit facility. In July 2010, the Company amended its revolving credit facility to increase its borrowing capacity to $400 million from $325 million, with the right, at the Company’s option, to increase the borrowing capacity of the facility to $550 million. Additionally, the amendment extended the maturity date to July 20, 2014. Costs associated with amending the revolving credit facility were approximately $5.2 million. These costs will be capitalized and amortized over the term of the newly amended credit facility. At September 30, 2010, the Company had $193.5 million outstanding under the revolving credit facility with a weighted average interest rate of 3.3% per annum. The Company also had approximately $8.9 million of letters of credit outstanding, which reduce the Company’s borrowing availability under this credit facility. Amounts borrowed under the credit facility bear interest at LIBOR 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 ability to pay dividends or make other distributions, make acquisitions, make changes to the Company’s capital structure, create liens or incur additional indebtedness. At September 30, 2010, the Company was in compliance with all such covenants.

At September 30, 2010, the Company had outstanding $13.8 million 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, 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 June 3^rd and December 3^rd of each year through the maturity date of June 3, 2027. The Company’s obligations are secured by mortgages on the two liftboats. In accordance with the agreement, the Company is required to comply with certain covenants and restrictions, including the maintenance of minimum net worth, working capital and debt-to-equity requirements. At September 30, 2010, the Company was in compliance with all such covenants.

The Company also has outstanding $300 million of 6 7/8% unsecured senior notes due 2014. The indenture governing the senior notes requires semi-annual interest payments on June 1^st and December 1^st of each year through the maturity date of June 1, 2014. The indenture contains certain covenants that, among other things, limit 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. At September 30, 2010, the Company was in compliance with all such covenants.

In March 2010, the Company entered into an interest rate swap agreement for a notional amount of $150 million, whereby the Company is entitled to receive semi-annual interest payments at a fixed rate of 6 7/8% per annum and is obligated to make quarterly interest payments at a variable rate. The variable interest rate, which is adjusted every 90 days, is based on LIBOR plus a fixed margin (see note 16).

The Company has outstanding $400 million of 1.50% unsecured senior exchangeable notes due 2026. Effective January 1, 2009, the Company retrospectively adopted authoritative guidance related to debt with conversion and other options, which requires the proceeds from the issuance of the 1.50% senior exchangeable notes to be allocated between a liability (issued at a discount) and an equity component. The resulting debt discount is amortized over the period the exchangeable debt is expected to be outstanding as additional non-cash interest expense. The Company used an effective interest rate of 6.89% and will amortize this debt discount through December 12, 2011. The Company has recorded an unamortized discount of $24.6 million and $38.9 million at September 30, 2010 and December 31, 2009, respectively, related to these exchangeable notes. The exchangeable notes bear interest at a rate of 1.50% per annum and decrease to 1.25% per annum on December 15, 2011. Interest on the exchangeable notes is payable semi-annually on December 15^th and June 15^th of each year through the maturity date of December 15, 2026. The exchangeable notes do not contain any restrictive financial covenants.

Under certain circumstances, holders may exchange the notes for shares of the Company’s common stock. The initial exchange rate is 21.9414 shares of common stock per $1,000 principal amount of notes. This is equal to an initial exchange price of $45.58 per share. The exchange price represents a 35% premium over the closing share price at date of issuance. The notes may be exchanged under the following circumstances:

	•		during any fiscal quarter (and only during such fiscal quarter), if the last reported sale price of the Company’s common stock is greater than or equal to 135% of the applicable exchange price of the notes for at least 20 trading days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter;
	•		prior to December 15, 2011, during the five business-day period after any ten consecutive trading-day period (the “measurement period”) in which the trading price of $1,000 principal amount of notes for each trading day in the measurement period was less than 95% of the product of the last reported sale price of the Company’s common stock and the exchange rate on such trading day;
	•		if the notes have been called for redemption;
	•		upon the occurrence of specified corporate transactions; or
	•		at any time beginning on September 15, 2026, and ending at the close of business on the second business day immediately preceding the maturity date of December 15, 2026.

Holders of the senior exchangeable notes may also require the Company to purchase all or a portion of their notes on December 15, 2011, December 15, 2016 and December 15, 2021 subject to certain administrative formalities. In each case, the purchase price payable will be equal to 100% of the principal amount of the notes to be purchased plus any accrued and unpaid interest with all amounts payable in cash.

In connection with the exchangeable note transaction, the Company simultaneously entered into agreements with affiliates of the initial purchasers to purchase call options and sell warrants on its common stock. The Company may exercise the call options it purchased at any time to acquire approximately 8.8 million shares of its common stock at a strike price of $45.58 per share. The owners of the warrants may exercise the warrants to purchase from the Company approximately 8.8 million shares of the Company’s common stock at a price of $59.42 per share, subject to certain anti-dilution and other customary adjustments. The warrants may be settled in cash, in common stock or in a combination of cash and common stock, at the Company’s option. Lehman Brothers OTC Derivatives, Inc. (LBOTC) is the counterparty to 50% of the Company’s call option and warrant transactions. In October 2008, LBOTC filed for bankruptcy protection. The Company continues to carefully monitor the developments affecting LBOTC. Although the Company may not retain the benefit of the call option due to LBOTC’s bankruptcy, the Company does not expect that there will be a material impact, if any, on the financial statements or results of operations. The call option and warrant transactions described above do not affect the terms of the outstanding exchangeable notes.

(8) Earnings per Share

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

In connection with the Company’s outstanding 1.50% senior exchangeable notes, there could be a dilutive effect on earnings per share if the price of the Company’s stock exceeds the initial exchange price of $45.58 per share for a specified period of time. In the event the Company’s common stock exceeds $45.58 per share for a specified period of time, the first $1.00 the price exceeds $45.58 would cause a dilutive effect of approximately 188,400 shares. The impact on the calculation of earnings per share varies depending on when during the quarter the $45.58 per share price is reached.

(9) Other Comprehensive Loss

The following tables reconcile the change in accumulated other comprehensive loss for the three and nine months ended September 30, 2010 and 2009 (in thousands):

		Three Months Ended
		September 30,
		2010				2009
Accumulated other comprehensive loss, June 30, 2010 and 2009, respectively		$	(31,464	)		$	(14,246	)
Other comprehensive income (loss):
Foreign currency translation adjustment			10,343				(4,338	)
Accumulated other comprehensive loss, September 30, 2010 and 2009, respectively		$	(21,121	)		$	(18,584	)

		Nine Months Ended
		September 30,
		2010				2009
Accumulated other comprehensive loss, December 31, 2009 and 2008, respectively		$	(18,996	)		$	(32,641	)
Other comprehensive income (loss):
Other comprehensive income (loss), net of tax
Hedging activities:
Unrealized loss on equity-method investments’ hedging activities, net of tax of ($2,279) in 2009			—				(3,881	)
Foreign currency translation adjustment			(2,125	)			17,938
Total other comprehensive income (loss)			(2,125	)			14,057
Accumulated other comprehensive loss, September 30, 2010 and 2009, respectively		$	(21,121	)		$	(18,584	)

(10) Decommissioning Liabilities

In connection with the recent acquisition of the Bullwinkle platform and its related assets, the Company records estimated future decommissioning liabilities in accordance with the authoritative guidance related to asset retirement obligations (decommissioning liabilities), which requires entities to record the fair value of a liability for an asset retirement obligation 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 associated with the Bullwinkle platform and its related assets consist of costs related to the plugging of wells, the removal of the related facilities and equipment, and site restoration.

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 assets. The Company reviews its estimates for the timing of these expenditures on a quarterly basis.

In connection with the acquisition of Superior Completion Services during the third quarter of 2010, the Company assumed approximately $10.0 million of decommissioning liabilities associated with restoring two chartered vessels to the original condition in which they were received (see note 2).

The following table summarizes the activity for the Company’s decommissioning liabilities for the nine month period ended September 30, 2010 (in thousands):

Decommissioning liabilities, December 31, 2009		$	—
Liabilities acquired			136,559
Accretion			5,361
Total decommissioning liabilities, September 30, 2010			141,920
Less: current portion			25,804
Long-term decommissioning liabilities, September 30, 2010		$	116,116

(11) Notes Receivable

Notes receivable consist of a commitment from the seller of certain assets to pay the Company upon the decommissioning of the Bullwinkle platform. These notes are recorded at present value, and the related discount is amortized to interest income based on the expected timing of the platform’s removal.

(12) Segment Information

Business Segments

During 2009, the Company renamed two of its segments in order to more accurately describe the markets and customers served by the businesses operating in each segment. The content of these segments has not changed, exclusive of the acquisitions of Superior Completion Services, Hallin and the Bullwinkle platform. The Company currently has three reportable segments: subsea and well enhancement (formerly well intervention), drilling products and services (formerly rental tools), and marine. The subsea and well enhancement segment provides production-related services used to enhance, extend and maintain oil and gas production, which include integrated subsea services and engineering solutions, mechanical wireline, hydraulic workover and snubbing, well control, coiled tubing, electric line, pumping and stimulation, well bore evaluation services; well plug and abandonment services; stimulation and sand control equipment and services; and other oilfield services used to support drilling and production operations. The subsea and well enhancement segment also includes production handling arrangements, as well as the production and sale of oil and gas. The drilling products and services 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 on-site 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.

Summarized financial information for the Company’s segments for the three and nine months ended September 30, 2010 and 2009 is shown in the following tables (in thousands):

Three Months September 30, 2010

		Subsea and				Drilling
		Well				Products and												Consolidated
		Enhancement				Services				Marine				Unallocated				Total
Revenues		$	289,048			$	118,727			$	27,578			$	—			$	435,353
Cost of services (exclusive of items shown separately below)			170,817				46,068				15,423				—				232,308
Depreciation, depletion, amortization and accretion			25,162				28,846				2,797				—				56,805
General and administrative expenses			53,043				28,394				3,475				—				84,912
Income from operations			40,026				15,419				5,883				—				61,328
Interest income (expense), net			1,343				—				—				(13,799	)			(12,456	)
Earnings from equity-method investments, net			—				—				—				3,030				3,030
Income (loss) before income taxes		$	41,369			$	15,419			$	5,883			$	(10,769	)		$	51,902

Three Months September 30, 2009

		Subsea and				Drilling
		Well				Products and												Consolidated
		Enhancement				Services				Marine				Unallocated				Total
Revenues		$	254,335			$	100,832			$	31,288			$	—			$	386,455
Cost of services (exclusive of items shown separately below)			160,237				36,211				19,226				—				215,674
Depreciation and amortization			22,602				26,789				3,329				—				52,720
General and administrative expenses			39,933				19,892				3,600				—				63,425
Income from operations			31,563				17,940				5,133				—				54,636
Interest expense, net			—				—				—				(12,320	)			(12,320	)
Loss from equity-method investments, net			—				—				—				(4,161	)			(4,161	)
Income (loss) before income taxes		$	31,563			$	17,940			$	5,133			$	(16,481	)		$	38,155

Nine Months September 30, 2010

		Subsea and				Drilling
		Well				Products and												Consolidated
		Enhancement				Services				Marine				Unallocated				Total
Revenues		$	806,166			$	354,341			$	64,213			$	—			$	1,224,720
Cost of services (exclusive of items shown separately below)			481,561				129,922				49,793				—				661,276
Depreciation, depletion, amortization and accretion			69,254				85,135				7,763				—				162,152
General and administrative expenses			158,746				79,584				9,835				—				248,165
Income (loss) from operations			96,605				59,700				(3,178	)			—				153,127
Interest income (expense), net			3,500				—				—				(42,674	)			(39,174	)
Earnings from equity-method investments, net			—				—				—				9,185				9,185
Income (loss) before income taxes		$	100,105			$	59,700			$	(3,178	)		$	(33,489	)		$	123,138

Nine Months September 30, 2009

		Subsea and				Drilling
		Well				Products and												Consolidated
		Enhancement				Services				Marine				Unallocated				Total
Revenues		$	773,513			$	329,309			$	81,903			$	—			$	1,184,725
Cost of services (exclusive of items shown separately below)			473,240				111,549				50,618				—				635,407
Depreciation and amortization			66,267				78,436				8,863				—				153,566
General and administrative expenses			113,154				65,952				9,588				—				188,694
Reduction in value of assets			92,683				—				—				—				92,683
Income from operations			28,169				73,372				12,834				—				114,375
Interest expense, net			—				—				—				(37,328	)			(37,328	)
Loss from equity-method investments, net			—				—				—				(21,331	)			(21,331	)
Reduction in value of equity-method investments			—				—				—				(36,486	)			(36,486	)
Income (loss) before income taxes		$	28,169			$	73,372			$	12,834			$	(95,145	)		$	19,230

Identifiable Assets

		Subsea and				Drilling
		Well				Products and												Consolidated
		Enhancement				Services				Marine				Unallocated				Total
September 30, 2010		$	1,783,215			$	789,513			$	286,916			$	82,791			$	2,942,435
December 31, 2009		$	1,377,122			$	759,418			$	299,834			$	80,291			$	2,516,665

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 (International) based on the physical location of the asset at the end of a period. The Company’s information by geographic area is as follows (in thousands):

		Three Months Ended September 30,								Nine Months Ended September 30,
Revenues:		2010				2009				2010				2009
United States		$	319,239			$	294,316			$	886,354			$	948,851
International			116,114				92,139				338,366				235,874
Total		$	435,353			$	386,455			$	1,224,720			$	1,184,725

		September 30,				December 31,
Long-Lived Assets:		2010				2009
United States		$	911,527			$	828,662
International			437,869				230,314
Total, net		$	1,349,396			$	1,058,976

(13) Guarantee

As part of SPN Resources’ acquisition of its oil and gas properties, the Company guaranteed SPN Resources’ performance of its decommissioning liabilities. In accordance with authoritative guidance related to guarantees, the Company has assigned an estimated value of $2.6 million and $2.7 million at September 30, 2010 and December 31, 2009, respectively, related to decommissioning performance guarantees, which is reflected in other long-term liabilities. The Company believes that the likelihood of being required to perform these guarantees is remote. In the unlikely event that SPN Resources defaults on the decommissioning liabilities, the total maximum potential obligation under these guarantees is estimated to be approximately $110.2 million, net of the contractual right to receive payments from third parties, which is approximately $24.6 million, as of September 30, 2010. The total maximum potential obligation will decrease over time as the underlying obligations are fulfilled by SPN Resources.

(14) Reduction in Value of Assets

In accordance with the authoritative guidance related to impairment or disposal of long-lived assets, assets such as property, plant and equipment and purchased intangibles subject to amortization are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of such assets to estimated undiscounted future cash flows expected to be generated by the assets. Cash flow estimates are based upon, among other things, historical results adjusted to reflect the best estimate of future market rates, utilization levels, and operating performance. The Company’s assets are grouped by subsidiary or division for impairment testing, except for liftboats, which are grouped together by leg length. These groupings represent the lowest level of identifiable cash flows. If the assets’ future estimated cash flows are less than the carrying amount of those items, impairment losses are recorded in the amount by which the carrying amount of such assets exceeds the fair value. The net carrying value of assets not fully recoverable is reduced to fair value. The estimate of fair value represents the Company’s best estimate based on industry trends and reference to market transactions and is subject to variability. The oil and gas industry is cyclical and these estimates of the period over which future cash flows will be generated, as well as the predictability of these cash flows, can have a significant impact on the carrying values of these assets and, in periods of prolonged down cycles, may result in impairment charges. During the second quarter of 2009, due to continued decline in demand for services in the domestic land markets, the Company identified impairments of certain amortizable intangible assets of approximately $92.7 million.

(15) Fair Value Measurements

The Company follows the authoritative guidance for fair value measurements relating to financial and nonfinancial assets and liabilities, including presentation of required disclosures herein. This guidance establishes a fair value framework requiring the categorization of assets and liabilities into three levels based upon the assumptions (inputs) used to price the assets and liabilities. Level 1 provides the most reliable measure of fair value, whereas Level 3 generally requires significant management judgment. The three levels are defined as follows:

Level 1:		Unadjusted quoted prices in active markets for identical assets and liabilities.

Level 2:		Observable inputs other than those included in Level 1 such as quoted prices for similar assets and liabilities in active markets; quoted prices for identical assets or liabilities in inactive markets; or model-derived valuations or other inputs that can be corroborated by observable market data.

Level 3:		Unobservable inputs reflecting management’s own assumptions about the inputs used in pricing the asset or liability.

The following table provides a summary of the financial assets and liabilities measured at fair value on a recurring basis at September 30, 2010 and December 31, 2009 (in thousands):

		September 30,				Fair Value Measurements at Reporting Date Using
		2010				Level 1				Level 2				Level 3
Intangible and other long-term assets
Non-qualified deferred compensation assets		$	11,789			$	2,235			$	9,554				—
Interest rate swap agreement		$	244				—			$	244				—
Accrued expenses
Non-qualified deferred compensation liabilities		$	1,905				—			$	1,905				—
Other long-term liabilities
Non-qualified deferred compensation liabilities		$	14,394				—			$	14,394				—
		December 31,
		2009				Level 1				Level 2				Level 3
Intangible and other long-term assets
Non-qualified deferred compensation assets		$	12,382			$	4,586			$	7,796				—
Other long-term liabilities
Non-qualified deferred compensation liabilities		$	15,758				—			$	15,758				—

The Company’s non-qualified deferred compensation plan allows officers and highly compensated employees to defer receipt of a portion of their compensation and contribute such amounts to one or more hypothetical investment funds (see note 4). The Company entered into a separate trust agreement, subject to general creditors, to segregate the assets of the plan and reports the accounts of the trust in its condensed consolidated financial statements. These investments are reported at fair value based on unadjusted quoted prices in active markets for identifiable assets and observable inputs for similar assets and liabilities, which represent Levels 1 and 2, respectively, in the fair value hierarchy. The realized and unrealized holding gains and losses related to non-qualified deferred compensation assets are recorded in interest expense, net. The realized and unrealized holding gains and losses related to non-qualified deferred compensation liabilities are recorded in general and administrative expenses.

In March 2010, the Company entered into an interest rate swap agreement for a notional amount of $150 million, whereby the Company is entitled to receive semi-annual interest payments at a fixed rate of 6 7/8% per annum and is obligated to make quarterly interest payments at a floating rate, which is adjusted every 90 days, based on LIBOR plus a fixed margin. The Company entered into the interest rate swap agreement in an effort to reduce its overall borrowing costs. The swap agreement, scheduled to terminate on June 1, 2014, is designated as a fair value hedge of a portion of the 6 7/8% unsecured senior notes, as the derivative has been tested to be highly effective in offsetting changes in the fair value of the underlying note. As this derivative is classified as a fair value hedge, the changes in the fair value of the derivative are offset against the changes in the fair value of the underlying note in interest expense, net (see note 16).

In 2009, the Company adopted the authoritative guidance regarding non-financial assets and non-financial liabilities that are remeasured at fair value on a non-recurring basis. In accordance with this guidance, long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. During the second quarter of 2009, due to continued decline in demand for services in the domestic land markets, the Company identified impairments of certain amortizable intangible assets of approximately $92.7 million (see note 14). Additionally, the Company recorded a $36.5 million reduction in the value of its equity-method investment in BOG (see note 6).

The following table reflects the fair value measurements used in testing the impairment of intangible assets and equity-method investments during the nine months ended September 30, 2009 (in thousands):

		September 30,				Fair Value Measurements Using												Total
		2009				Level 1				Level 2				Level 3				Losses
Intangible and other long-term assets, net		$	-0-				—				—			$	-0-			$	(92,683	)
Equity-method investments		$	-0-				—				—			$	-0-			$	(36,486	)

The fair value of the Company’s financial instruments of cash equivalents, accounts receivable, equity-method investments and current maturities of long-term debt approximates their carrying amounts. The fair value of the Company’s long-term debt was approximately $899.2 million and $853.2 million at September 30, 2010 and December 31, 2009, respectively. The fair value of these debt instruments is determined by reference to the market value of the instrument as quoted in an over-the-counter market.

(16) Derivative Financial Instruments

The Company manages its debt portfolio by targeting an overall desired position of fixed and floating rates and may employ interest rate swaps from time to time to achieve its goal. The Company does not use derivative financial instruments for trading or speculative purposes.

In March 2010, the Company entered into an interest rate swap agreement that effectively converted $150 million of fixed rate debt maturing in 2014 to floating rate debt. The transaction was entered into with the goal of reducing overall borrowing costs. This transaction was designated as a fair value hedge since the swap hedges against the change in fair value of fixed rate debt resulting from changes in interest rates. The Company recorded a derivative asset of $0.2 million within intangible and other long-term assets in the condensed consolidated balance sheet as of September 30, 2010 (see note 7). The change in fair value of the interest rate swap is included in the adjustments to reconcile net income to net cash provided by operating activities in the Condensed Consolidated Statements of Cash Flows.

The location and effect of the derivative instrument on the condensed consolidated statements of operations for the three and nine month periods ended September 30, 2010, presented on a pre-tax basis, is as follows (in thousands):

				Amount of (gain) loss recognized
		Location of		Three Months				Nine Months
		(gain) loss		Ended				Ended
		recognized		September 30, 2010				September 30, 2010
Interest rate swap		Interest expense, net		$	(1,422	)		$	(2,937	)
Hedged item — debt		Interest expense, net			806				2,693
				$	(616	)		$	(244	)

For the nine months ended September 30, 2010, approximately $0.2 million of interest income was related to the ineffectiveness associated with this fair value hedge. Hedge ineffectiveness represents the difference between the changes in fair value of the derivative instruments and the changes in fair value of the fixed rate debt attributable to changes in the benchmark interest rate.

(17) Income Taxes

The Company follows authoritative guidance surrounding accounting for uncertainty in income taxes. It is the Company’s policy to recognize interest and applicable penalties, if any, related to uncertain tax positions in income tax expense. In the nine month period ended September 30, 2010, the Company’s recognition of unrecorded tax benefits increased to $27.5 million as of September 30, 2010 from $11.0 million as of December 31, 2009. This increase was related to foreign income tax attributable to the Hallin acquisition (see note 2).

In addition to its U.S. federal tax return, the Company files income tax returns in various state and foreign jurisdictions. The number of years that are open under the statute of limitations and subject to audit varies depending on the tax jurisdiction. The Company remains subject to U.S. federal tax examinations for years after 2006.

(18) Commitments and Contingencies

Due to the nature of the Company’s business, the Company is involved, from time to time, in routine litigation or subject to disputes or claims regarding our business activities. Legal costs related to these matters are expensed as incurred. In management’s opinion, none of the pending litigation, disputes or claims is expected to have a material adverse effect on the Company’s financial condition, results of operations or liquidity.

(19) Subsequent Events

In 2009, the Financial Accounting Standards Board issued authoritative guidance regarding subsequent events, which establishes general standards of accounting for, and disclosure of, events that occur after the balance sheet date, but before financial statements are issued or are available to be issued. In accordance with this guidance, the Company has evaluated and disclosed all material subsequent events that occurred after the balance sheet date, but before financial statements were issued.

(20) New Accounting Pronouncements

On January 1, 2010, the Company adopted Accounting Standards Codification 810-10 (ASC 810-10), “Amendments to FASB Interpretation No. 46(R), Consolidation of Variable Interest Entities,” for determining whether an entity is a variable interest entity (VIE) and requires an enterprise to perform an analysis to determine whether the enterprise’s variable interest or interests give it a controlling financial interest in a VIE. ASC 810-10 also requires ongoing assessments of whether an enterprise is the primary beneficiary of a VIE, requires enhanced disclosures and eliminates the scope exclusion for qualifying special-purpose entities. The adoption of ASC 810-10 did not have a significant impact on the results of operations and financial position.

On January 1, 2010, the Company adopted Accounting Standards Update 2010-06 (ASU 2010-06), “Improving Disclosures about Fair Value Measurements.” The update provides an amendment to ASC 820-10, “Fair Value Measurements and Disclosures,” requiring additional disclosures of significant transfers between Level 1 and Level 2 within the fair value hierarchy, as well as information about purchases, sales, issuances and settlements using unobservable inputs (Level 3). ASU 2010-06 is effective for interim and annual reporting periods beginning after December 15, 2009 for new disclosures and clarifications of existing disclosures, except for disclosures about purchases, sales, issuances and settlements in the rollforward of activity in the Level 3 fair value measurements, which are effective for fiscal years beginning after December 15, 2010. The adoption of ASU 2010-06 did not have a significant impact on the results of operations and financial position.

In October 2009, the Financial Accounting Standards Board issued Accounting Standards Update 2009-13 (ASU 2009-13), “Multiple-Deliverable Revenue Arrangements.” The new standard changes the requirements for establishing separate units of accounting in a multiple element arrangement and requires the allocation of arrangement consideration to each deliverable based on the relative selling price. The selling price for each deliverable is based on vendor-specific objective evidence (VSOE) if available, third-party evidence if VSOE is not available, or estimated selling price if neither VSOE or third-party evidence is available. ASU 2009-13 is effective for revenue arrangements entered into in fiscal years beginning on or after June 15, 2010. The Company is currently evaluating the impact the adoption of ASU 2009-13 will have, if any, on its results of operations and financial position.

In January 2010, the Financial Accounting Standards Board issued Accounting Standards Update 2010-03 (ASU 2010-03), “Oil and Gas Reserve Estimation and Disclosures.” The update provides an amendment to Accounting Standards Codification 932 (ASC 932), “Extractive Activities – Oil and Gas,” that expands the definition of oil- and gas-producing activities and requires disclosures of reserve quantities and standardized measure of cash flows for equity-method investments that have significant oil- and gas-producing activities. ASU 2010-03 is effective for annual reporting periods ending on or after December 31, 2009. ASU 2010-03 allows an entity that becomes subject to the disclosure requirements of ASC 932 due to the change to the definition of significant oil- and gas-producing activities to apply the disclosure provisions of ASC 932 in annual periods beginning after December 31, 2009. As such, the Company has elected to defer the application of ASU 2010-03 until the annual reporting period ended December 31, 2010. The Company is currently evaluating the impact the adoption of ASU 2010-03 will have on its results of operations and financial position.

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

Forward-Looking Statements

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 market and industry 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 effect of regulatory programs and environmental matters on the Company’s performance; risks associated with the uncertainty of macroeconomic and business conditions worldwide, as well as the global credit markets; the cyclical nature and volatility of the oil and gas industry, including the level of offshore exploration, production and development activity and the volatility of oil and gas prices; changes in competitive factors affecting the Company’s operations; political, economic and other risks and uncertainties associated with international operations; the seasonality of the offshore industry in the Gulf of Mexico; the potential shortage of skilled workers; the Company’s dependence on certain customers; the risks inherent in long-term fixed-price contracts; operating hazards, including the significant possibility of accidents resulting in personal injury, property damage or environmental damage; and risks inherent in acquiring businesses. These risks 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, 2009 and in Part II, Item 1A herein. 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. Investors are cautioned that many of the assumptions on which our forward-looking statements are based are likely to change after our forward-looking statements are made, including for example the market prices of oil and natural gas and regulations affecting oil and gas operations, which we cannot control or anticipate. Further, during the quarter, we may make changes to our business plans that could or will affect our results for the quarter. We do not intend to update our forward-looking statements more frequently than quarterly, notwithstanding any changes in our assumptions, changes in our business plans, our actual experience, or other changes. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date hereof.

Executive Summary

During the third quarter of 2010, revenue was $435.4 million, income from operations was $61.3 million, net income was $33.2 million and diluted earnings per share was $0.42.

Revenue growth continues to strengthen in the domestic land markets as the average number of rigs drilling for oil and gas increased by 10% over the second quarter of 2010. Revenue from domestic land markets increased 31% over the second quarter of 2010 to $157.6 million, the most quarterly revenue we have generated from the domestic land markets in our history. In addition, international revenue was also a quarterly record, increasing 3% over the second quarter of 2010 to $116.1 million. These results were partially offset by a 16% decrease in Gulf of Mexico revenue primarily due to reduced demand for drilling products and services as a result of the deepwater drilling moratorium, and less engineering and project management work.

Subsea and well enhancement segment revenue was $289.0 million, a 2% increase from the second quarter of 2010, and income from operations was $40.0 million, a 22% increase from the second quarter of 2010. Our Gulf of Mexico revenue from this segment decreased 19% to $104.5 million from the second quarter of 2010 primarily due to a reduction in engineering and project management services and reduced revenue from the wreck removal project. Domestic land revenue in this segment increased 31% sequentially due to increased demand for coiled tubing, cased hole wireline, well control services and hydraulic workover and snubbing services. International revenue in this segment increased 4% sequentially due to increases in subsea and well control services.

In our drilling products and services segment, revenue was $118.7 million, a 2% decrease as compared with the second quarter of 2010, and income from operations was $15.4 million, a 24% decrease from the second quarter of 2010. Income from operations as a percentage of revenue decreased 4% as rentals of high-margin drill pipe, specialty tubulars and stabilization equipment fell significantly in the Gulf of Mexico due to the deepwater drilling moratorium. This segment’s Gulf of Mexico revenue decreased 29% from the second quarter of 2010. Revenue

from the domestic land markets increased 31% sequentially, primarily due to increased rentals of accommodations, specialty tubulars and stabilization equipment. International revenue was essentially unchanged from the prior quarter.

In our marine segment, revenue was $27.6 million, a 44% increase over the second quarter of 2010. Income from operations was $5.9 million compared with a loss from operations of $5.1 million in the most recent quarter. Utilization of our liftboats increased to 88% from 62% in the second quarter of 2010 as a result of several liftboats working on the Macondo oil spill and the return to service of our two 250-foot class liftboats, which spent much of the second quarter in the shipyard for maintenance and repairs. Our performance also benefitted from a 44% reduction in repair and maintenance expenses.

Much of the work we have performed supporting response efforts on the Macondo oil spill will be concluding early in the fourth quarter. Although the deepwater drilling moratorium in the Gulf of Mexico was lifted early in the fourth quarter of 2010, we do not anticipate demand for drilling products and services to return to pre-moratorium levels for some time. The industry continues the process of understanding and implementing new regulations as they are issued. As a result, it may be several quarters before a large percentage of the pre-moratorium deepwater drilling resumes. In addition, the number of rigs drilling in the shallow water may not increase materially in the coming quarters as very few new drilling permits have been issued for drilling on the Outer Continental Shelf.

Comparison of the Results of Operations for the Three Months Ended September 30, 2010 and 2009

For the three months ended September 30, 2010, our revenues were $435.4 million, resulting in net income of $33.2 million, or $0.42 diluted earnings per share. For the three months ended September 30, 2009, revenues were $386.5 million and net income was $24.4 million, or $0.31 earnings per share. Included in the results for the three months ended September 30, 2009 were $6.2 million of non-cash losses from equity-method investments that include $1.5 million of our share of unrealized losses associated with mark-to-market changes in the value of outstanding hedging contracts put in place by SPN Resources and $4.7 million of other non-cash charges related to SPN Resources. Revenues for the three months ended September 30, 2010 were higher in the subsea and well enhancement segment due to the current year acquisitions coupled with an increase in demand for coiled tubing services, specifically in the U.S. land market areas. Revenue also increased in the drilling products and services segment primarily due to increased rentals of stabilization equipment and accommodation units. During the three months ended September 30, 2010, revenue in our marine segment decreased due to the fact that our 265-foot class liftboats were out of service for the entire period for repairs.

The following table compares our operating results for the three months ended September 30, 2010 and 2009 (in thousands). Cost of services excludes depreciation, depletion, amortization and accretion for each of our business segments.

		Revenue												Cost of Services
		2010				2009				Change				2010				%				2009				%				Change
Subsea and Well Enhancement		$	289,048			$	254,335			$	34,713			$	170,817				59	%		$	160,237				63	%		$	10,580
Drilling Products and Services			118,727				100,832				17,895				46,068				39	%			36,211				36	%			9,857
Marine			27,578				31,288				(3,710	)			15,423				56	%			19,226				61	%			(3,803	)
Total		$	435,353			$	386,455			$	48,898			$	232,308				53	%		$	215,674				56	%		$	16,634

The following provides a discussion of our results on a segment basis:

Subsea and Well Enhancement

Revenue from our subsea and well enhancement segment was $289.0 million for the three months ended September 30, 2010, as compared with $254.3 million for the same period in 2009. Cost of services percentage decreased to 59% of segment revenue for the three months ended September 30, 2010 from 63% for the same period in 2009. Our increase in revenue and profitability is primarily attributable to the increase in the domestic land and international market areas. Revenue from our domestic land market areas increased

approximately 125% due to demand for coiled tubing, wireline, well control services and hydraulic workover and snubbing services in connection with the increase in rig count. Additionally, revenue from our international market areas increased approximately 46% primarily due to our acquisition of Hallin, offset partially by a reduction in derrick barge and inspection, repair and maintenance activity off the coast of West Africa. Revenue from our Gulf of Mexico market area decreased approximately 32% due to the fact that we performed less work associated with our large-scale decommissioning project. This decrease was partially offset by increased well control work and our acquisitions of Superior Completion Services and the Bullwinkle platform.

Drilling Products and Services Segment

Revenue from our drilling products and services segment for the three months ended September 30, 2010 was $118.7 million, as compared to $100.8 million for the same period in 2009. Cost of rentals and sales percentage increased to 39% of segment revenue for the three months ended September 30, 2010 from 36% for the same period of 2009. The increase in revenue for this segment is primarily related to an increase in rentals of specialty tubulars, stabilization equipment and accommodation units in our domestic land market areas along with rentals of drill pipe in our international market areas. Revenue in our domestic land market areas more than doubled for the quarter ended September 30, 2010 over the same period in 2009. Revenue generated from our international market areas increased approximately 2% for the quarter ended September 30, 2010 over the same period in 2009. The increases in drill pipe rental were offset by decreases in accommodation rentals. Revenue from our Gulf of Mexico market area decreased approximately 18% due to a decreased demand for specialty tubulars as a result of the deepwater drilling moratorium. Cost of services as a percentage of revenue increased 3% as rentals of high-margin drill pipe, specialty tubulars and stabilization equipment fell significantly in the Gulf of Mexico due to the deepwater drilling moratorium.

Marine Segment

Our marine segment revenue for the three months ended September 30, 2010 was $27.6 million, a 12% decrease over the same period in 2009. Our cost of services percentage decreased to 56% of segment revenue for the three months ended September 30, 2010 from 61% for the same period in 2009 primarily due to decreased liftboat inspections and maintenance costs. Due to the high fixed cost nature of this segment, cost of services does not fluctuate proportionately with revenue. The fleet’s average utilization increased to approximately 88% for the third quarter of 2010 from 62% in the same period in 2009. Conversely, the fleet’s average dayrate decreased to approximately $12,300 for the third quarter of 2010 from $16,300 in the same period in 2009.

The average dayrate decreased as our two completed 265-foot class liftboats were out of service for the entire period for repairs. We anticipate both 265-foot class liftboats will return to service in the fourth quarter of 2010. Construction on the remaining two 265-foot class liftboats was suspended in March 2009, as a result of disputes with the builder. Those disputes have been resolved and the uncompleted vessels have been delivered to a different shipyard to be completed. We are currently in the process of redesigning these two partially constructed 265-foot class liftboats in order to meet market demand.

Depreciation, Depletion, Amortization and Accretion

Depreciation, depletion, amortization and accretion increased to $56.8 million in the three months ended September 30, 2010 from $52.7 million in the same period in 2009. Depreciation, depletion, amortization and accretion expense related to our subsea and well enhancement segment for the three months ended September 30, 2010 increased approximately $2.6 million, or 11%, from the same period in 2009. This increase is primarily due to the acquisitions of Superior Completion Services, Hallin and the Bullwinkle platform, along with 2009 and 2010 capital expenditures, which was partially offset by the decrease in depreciation and amortization expense as a result of the $212.5 million reduction in value of assets related to our domestic land market areas recorded in 2009. Depreciation and amortization expense increased within our drilling products and services segment by $2.1 million, or 8%, due to 2009 and 2010 capital expenditures. Depreciation expense related to the marine segment for the three months ended September 30, 2010 decreased slightly from the same period in 2009. This decrease in depreciation expense is due to the fact that our two completed 265-foot class liftboats were out of service for the entire period for repairs. This decrease, coupled with the fact that we sold four 145-foot leg length liftboats in November 2009, was partially offset by higher utilization.

General and Administrative Expenses

General and administrative expenses increased to $84.9 million for the three months ended September 30, 2010 from $63.4 million for the same period in 2009. The increase is primarily related to our recent acquisitions, increased bonus and compensation expense due to our improved performance, and additional infrastructure to enhance our growth.

Comparison of the Results of Operations for the Nine Months Ended September 30, 2010 and 2009

For the nine months ended September 30, 2010, our revenues were $1,224.7 million, resulting in net income of $78.8 million, or $0.99 diluted earnings per share. Included in the results for the nine months ended September 30, 2010 were pre-tax management transition expenses of $19.0 million. For the nine months ended September 30, 2009, revenues were $1,184.7 million and net income was $12.3 million, or $0.16 diluted earnings per share. Included in the results for the nine months ended September 30, 2009 were non-cash, pre-tax charges of $92.7 million for the reduction in value of intangible assets and $36.5 million for the reduction in value of our remaining equity-method investment in BOG. Also included in the results for the nine months ended September 30, 2009 were losses of $14.0 million from our share of BOG, $8.9 million of our share of unrealized losses associated with mark-to-market changes in the value of the outstanding hedges put in place by SPN Resources and $4.7 million of other non-cash charges related to SPN Resources. Revenues for the nine months ended September 30, 2010 were higher in the subsea and well enhancement segment primarily due to the current year acquisitions of Superior Completion Services, Hallin and the Bullwinkle platform. Additionally, increases in demand for coiled tubing services and wireline services, specifically in the U.S. land market areas, contributed to the increase in revenue. Revenue increased in the drilling products and services segment primarily due to increased rentals of specialty tubulars and accommodation units. During the nine months ended September 30, 2010, revenue in our marine segment decreased due to the fact that our 265-foot class liftboats were out of service for the entire period for repairs.

The following table compares our operating results for the nine months ended September 30, 2010 and 2009 (in thousands). Cost of services excludes depreciation, depletion, amortization and accretion for each of our business segments.

		Revenue												Cost of Services
		2010				2009				Change				2010				%				2009				%				Change
Subsea and Well Enhancement		$	806,166			$	773,513			$	32,653			$	481,561				60	%		$	473,240				61	%		$	8,321
Drilling Products and Services			354,341				329,309				25,032				129,922				37	%			111,549				34	%			18,373
Marine			64,213				81,903				(17,690	)			49,793				78	%			50,618				62	%			(825	)
Total		$	1,224,720			$	1,184,725			$	39,995			$	661,276				54	%		$	635,407				54	%		$	25,869

The following provides a discussion of our results on a segment basis:

Subsea and Well Enhancement

Revenue from our subsea and well enhancement segment was $806.2 million for the nine months ended September 30, 2010, as compared with $773.5 million for the same period in 2009. Cost of services percentage decreased slightly to 60% of segment revenue for the nine months ended September 30, 2010 from 61% for the same period in 2009. Our increase in revenue and profitability is primarily attributable to increases in the domestic land and international market areas. Revenue from our domestic land market areas increased approximately 60% due to demand for coiled tubing, wireline, well control services and hydraulic workover and snubbing services. Additionally, revenue from our international market areas increased approximately 79% primarily due to our acquisition of Hallin along with revenue from our well control services and hydraulic workover and snubbing services. Revenue from our Gulf of Mexico market area decreased approximately 32% primarily based on a decline in revenue from work associated with our large-scale decommissioning project. This decrease was partially offset by increased well control work and plug and abandonment activity, as well as our acquisitions of Superior Completion Services and the Bullwinkle platform.

Drilling Products and Services Segment

Revenue from our drilling products and services segment for the nine months ended September 30, 2010 was $354.3 million, as compared to $329.3 million for the same period in 2009. Cost of rentals and sales percentage increased to 37% of segment revenue for the nine months ended September 30, 2010 from 34% for the same period of 2009. The increase in revenue for this segment is primarily related to accommodation rentals, specifically in our domestic land market areas, as well as specialty tubulars. Revenue in our domestic land market areas increased approximately 27% for the nine months ended September 30, 2010 over the same period in 2009. Revenue generated from our international market areas increased approximately 5% for the nine months ended September 30, 2010 over the same period in 2009, primarily due to increased activity in Latin America. Revenue from our Gulf of Mexico market area decreased approximately 3% due to decreased demand for specialty tubulars as result of the deepwater drilling moratorium. The decrease in specialty tubulars was partially offset by accommodation rentals. Cost of services as a percentage of revenue increased 3% as rentals of high-margin drill pipe, specialty tubulars and stabilization equipment fell significantly in the Gulf of Mexico due to the deepwater drilling moratorium.

Marine Segment

Our marine segment revenue for the nine months ended September 30, 2010 was $64.2 million, a 22% decrease over the same period in 2009. Our cost of services percentage increased to 78% of segment revenue for the nine months ended September 30, 2010 from 62% for the same period in 2009 primarily due to increased liftboat inspections and maintenance costs coupled with decreased revenue. Due to the high fixed cost nature of this segment, cost of services does not fluctuate proportionately with revenue. The fleet’s average utilization increased to approximately 66% for the nine months ending September 30, 2010 from 55% in the same period in 2009. However, the fleet’s average dayrate decreased to approximately $13,000 for the first nine months of 2010 from $16,900 in the same period in 2009. The average dayrate decreased as several of our larger liftboats were not available for work due to inspections and repairs. Both of our 250-foot class liftboats were out of service for an extended period of time for U.S. Coast Guard inspections. Additionally, our two completed 265-foot class liftboats were out of service for the entire period for repairs.

Depreciation, Depletion, Amortization and Accretion

Depreciation, depletion, amortization and accretion increased to $162.2 million in the nine months ended September 30, 2010 from $153.6 million in the same period in 2009. Depreciation, depletion, amortization and accretion expense related to our subsea and well enhancement segment for the nine months ended September 30, 2010 increased $3.0 million, or 5%, from the same period in 2009. Increases in depreciation, depletion, amortization and accretion related to the acquisitions of Superior Completion Services, Hallin and the Bullwinkle platform, along with 2009 and 2010 capital expenditures, were offset by the decrease in depreciation and amortization expense as a result of the $212.5 million reduction in value of assets related to our domestic land market areas recorded in 2009. Depreciation and amortization expense increased within our drilling products and services segment by $6.7 million, or 9%, due to 2009 and 2010 capital expenditures. Depreciation expense related to the marine segment for the nine months ended September 30, 2010 decreased $1.1 million, or 12%. This decrease in depreciation expense in our marine segment is attributable to lower utilization in our larger fleet coupled with the sale of four 145-foot leg length liftboats in November 2009. This decrease was partially offset due to higher utilization in our smaller fleet.

General and Administrative Expenses

General and administrative expenses increased to $248.2 million for the nine months ended September 30, 2010 from $188.7 million for the same period in 2009. The increase is primarily related to pre-tax management transition expenses along with our recent acquisitions. Other increases include increased bonus and compensation expense due to our improved performance and additional infrastructure to enhance our growth.

Liquidity and Capital Resources

In the nine months ended September 30, 2010, we generated net cash from operating activities of $336.8 million as compared to $176.9 million in the same period of 2009. This increase is primarily attributable to the billings and receipt of payments related to the large-scale decommissioning contract in the Gulf of Mexico. Included in other current assets is approximately $109.9 million and $209.5 million at September 30, 2010 and December 31, 2009,

respectively, of costs and estimated earnings in excess of billings related to this project. Billings, and subsequent receipts, are based on the completion of milestones. Our primary liquidity needs are for working capital, and to fund capital expenditures, debt service and acquisitions. Our primary sources of liquidity are cash flows from operations and available borrowings under our revolving credit facility. We had cash and cash equivalents of $47.4 million at September 30, 2010 compared to $206.5 million at December 31, 2009.

We spent $238.8 million of cash on capital expenditures during the nine months ended September 30, 2010. Approximately $94.0 million was used to expand and maintain our drilling products and services equipment inventory, approximately $19.4 million was spent on our marine segment and approximately $111.3 million was used to expand and maintain the asset base of our subsea and well enhancement segment, including the purchase of a 220-foot dynamically positioned vessel.

In January 2010, we acquired Hallin, for approximately $162.3 million of cash. Additionally, we repaid approximately $55.5 million of Hallin’s debt. Hallin is an international provider of integrated subsea services and engineering solutions, focused on installing, maintaining and extending the life of subsea wells. Hallin operates in international offshore oil and gas markets with offices and facilities located in Singapore, Indonesia, Australia, Scotland and the United States.

In August 2010, we purchased Superior Completion Services which consists of certain assets, used in Baker Hughes’ Gulf of Mexico stimulation and sand control business, for approximately $54.3 million. Baker Hughes was required to divest this business by the Department of Justice in connection with its acquisition of BJ Services Company. This acquisition of these assets, along with a manufacturing facility and related product line, provides us greater exposure to well completions and intervention projects earlier in the life cycle of the well.

In July 2010, we amended our bank revolving credit facility to increase the borrowing capacity to $400 million from $325 million, with the right, at our option, to increase the borrowing capacity of the facility to $550 million. Any amounts outstanding under the revolving credit facility are due on July 20, 2014. At September 30, 2010, we had $193.5 million outstanding under the bank credit facility with a weighted average interest rate of 3.3% per annum. Our borrowings under the revolving credit facility increased $53.9 million during the quarter due to the acquisition of Superior Completion Services. We anticipate collecting $154.4 million late in the fourth quarter in connection with the large-scale platform decommissioning project in the Gulf of Mexico, pending certain regulatory approvals. This receipt of cash will significantly decrease the balance on our credit facility. At November 1, 2010, we had $195.4 million outstanding under the bank credit facility with a weighted average interest rate of 3.6% per annum. We also had $8.9 million of letters of credit outstanding, which reduces our borrowing capacity under this credit facility. Borrowings under the credit facility bear interest at LIBOR 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 of our principal subsidiaries. The credit facility contains customary events of default and requires that we satisfy various financial covenants. It also limits our ability to pay dividends or make other distributions, make acquisitions, create liens or incur additional indebtedness.

At September 30, 2010, we had outstanding $13.8 million 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 June 3^rd and December 3^rd of each year through the maturity date of 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, working capital and debt-to-equity requirements.

We have outstanding $300 million of 6 7/8% unsecured senior notes due 2014. The indenture governing the senior notes requires semi-annual interest payments on June 1^st and December 1^st of each year through the maturity date of June 1, 2014. The indenture contains certain covenants that, among other things, limit 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.

The Company’s current long-term issuer credit rating is BB+ by Standard and Poor’s and Ba3 by Moody’s. Our credit rating may be impacted by the rating agencies’ view of the cyclical nature of our industry sector.

We also have outstanding $400 million of 1.50% senior exchangeable notes due 2026. The exchangeable notes bear interest at a rate of 1.50% per annum and decrease to 1.25% per annum on December 15, 2011. Interest on the exchangeable notes is payable semi-annually in arrears on December 15^th and June 15^th of each year through the maturity date of December 15, 2026. The exchangeable notes do not contain any restrictive financial covenants.

Under certain circumstances, holders may exchange the notes for shares of our common stock. The initial exchange rate is 21.9414 shares of common stock per $1,000 principal amount of notes. This exchange rate is equal to an initial exchange price of $45.58 per share. The exchange price represents a 35% premium over the closing share price at the date of issuance. The notes may be exchanged under the following circumstances:

	•		during any fiscal quarter (and only during such fiscal quarter), if the last reported sale price of our common stock is greater than or equal to 135% of the applicable exchange price of the notes for at least 20 trading days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter;
	•		prior to December 15, 2011, during the five business-day period after any ten consecutive trading-day period (the “measurement period”) in which the trading price of $1,000 principal amount of notes for each trading day in the measurement period was less than 95% of the product of the last reported sale price of our common stock and the exchange rate on such trading day;
	•		if the notes have been called for redemption;
	•		upon the occurrence of specified corporate transactions; or
	•		at any time beginning on September 15, 2026, and ending at the close of business on the second business day immediately preceding the maturity date of December 15, 2026.

Holders of the senior exchangeable notes may also require us to purchase all or a portion of their notes on December 15, 2011, December 15, 2016 and December 15, 2021 subject to certain administrative formalities. In each case, the purchase price payable will be equal to 100% of the principal amount of the notes to be purchased plus any accrued and unpaid interest with all amounts payable in cash.

In connection with the issuance of the exchangeable notes, we entered into agreements with affiliates of the initial purchasers to purchase call options and sell warrants on our common stock. We may exercise the call options we purchased at any time to acquire approximately 8.8 million shares of our common stock at a strike price of $45.58 per share. The owners of the warrants may exercise the warrants to purchase from us approximately 8.8 million shares of our common stock at a price of $59.42 per share, subject to certain anti-dilution and other customary adjustments. The warrants may be settled in cash, in common stock or in a combination of cash and common stock, at our option. These transactions may potentially reduce the dilution of our common stock from the exchange of the notes by increasing the effective exchange price to $59.42 per share. Lehman Brothers OTC Derivatives, Inc. (LBOTC) is the counterparty to 50% of our call option and warrant transactions. In October 2008, LBOTC filed for bankruptcy protection. We continue to carefully monitor the developments affecting LBOTC. Although we may not retain the benefit of the call option due to LBOTC’s bankruptcy, we do not expect that there will be a material impact, if any, on the financial statements or results of operations. The call option and warrant transactions described above do not affect the terms of the outstanding exchangeable notes.

The following table summarizes our contractual cash obligations and commercial commitments at September 30, 2010 (amounts in thousands) for our long-term debt (including estimated interest payments), operating leases and other long-term liabilities. We do not have any other material obligations or commitments.

		Remaining Three
Description		Months 2010				2011				2012				2013				2014				2015				Thereafter
Long-term debt, including estimated interest payments		$	16,515			$	37,942			$	37,390			$	37,338			$	516,797			$	6,449			$	467,904
Decommissioning liabilities			5,276				28,776				7,891				10,858				4,155				84,964				—
Operating leases			4,118				11,053				7,359				4,785				3,678				1,435				11,564
Vessel construction			14,917				22,375				29,834				—				—				—				—
Other long-term liabilities			—				16,241				26,546				20,035				13,109				7,784				32,698
Total		$	40,826			$	116,387			$	109,020			$	73,016			$	537,739			$	100,632			$	512,166

We currently believe that we will spend approximately $150 million to $160 million on capital expenditures, excluding acquisitions, during the remaining three months of 2010. 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.

In May 2010, we signed a contract for construction of a compact semi-submersible vessel. This vessel is designed for both shallow and deepwater conditions and will be capable of performing subsea construction, inspection, repairs and maintenance work as well as subsea light well intervention and abandonment work.

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.

Off-Balance Sheet Financing Arrangements

We have no off-balance sheet financing arrangements other than potential additional consideration that may be payable as a result of the future operating performances of certain acquisitions. At September 30, 2010, the maximum additional consideration payable for these acquisitions was approximately $18.0 million. Since these acquisitions occurred before we adopted the revised authoritative guidance for business combinations, these amounts are not classified as liabilities 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. In the nine months ended September 30, 2010, the Company paid additional consideration of approximately $1.3 million as a result of prior acquisitions. During the fourth quarter of 2010, we will pay approximately $13.0 million of additional consideration for a previous acquisition.

Hedging Activities

In an effort to reduce our overall borrowing costs, we entered into an interest rate swap in March 2010 that effectively converted certain fixed-rate debt instruments into floating-rate debt instruments. Interest rate swap agreements that are effective at hedging the fair value of fixed-rate debt agreements are designated and accounted for as fair value hedges. At September 30, 2010, we have fixed-rate interest on approximately 62% of our long-term

debt. As of September 30, 2010, we had $150 million of long-term debt with a variable interest rate, which is adjusted every 90 days, based on LIBOR plus a fixed margin.

From time to time, we enter into forward foreign exchange contracts to mitigate the impact of foreign currency fluctuations. The forward foreign exchange contracts we enter into generally have maturities ranging from one to eighteen months. We do not enter into forward foreign exchange contracts for trading purposes. During the nine months ended September 30, 2009, we held outstanding foreign currency forward contracts in order to hedge exposure to currency fluctuations between the British Pound Sterling and the Euro. These contracts were not accounted for as hedges and were marked to fair market value each period. As of September 30, 2010, we had no outstanding foreign currency forward contracts.

New Accounting Pronouncements

On January 1, 2010, we adopted Accounting Standards Codification 810-10 (ASC 810-10), “Amendments to FASB Interpretation No. 46(R), Consolidation of Variable Interest Entities,” for determining whether an entity is a variable interest entity (VIE) and requires an enterprise to perform an analysis to determine whether the enterprise’s variable interest or interests give it a controlling financial interest in a VIE. ASC 810-10 also requires ongoing assessments of whether an enterprise is the primary beneficiary of a VIE, requires enhanced disclosures and eliminates the scope exclusion for qualifying special-purpose entities. The adoption of ASC 810-10 did not have a significant impact on our results of operations and financial position.

On January 1, 2010, we adopted Accounting Standards Update 2010-06 (ASU 2010-06), “Improving Disclosures about Fair Value Measurements.” The update provides an amendment to ASC 820-10, “Fair Value Measurements and Disclosures,” requiring additional disclosures of significant transfers between Level 1 and Level 2 within the fair value hierarchy, as well as information about purchases, sales, issuances and settlements using unobservable inputs (Level 3). ASU 2010-06 is effective for interim and annual reporting periods beginning after December 15, 2009 for new disclosures and clarifications of existing disclosures, except for disclosures about purchases, sales, issuances and settlements in the rollforward of activity in the Level 3 fair value measurements, which are effective for fiscal years beginning after December 15, 2010. The adoption of ASU 2010-06 did not have a significant impact on our results of operations and financial position.

In October 2009, the Financial Accounting Standards Board issued Accounting Standards Update 2009-13 (ASU 2009-13), “Multiple-Deliverable Revenue Arrangements.” The new standard changes the requirements for establishing separate units of accounting in a multiple element arrangement and requires the allocation of arrangement consideration to each deliverable based on the relative selling price. The selling price for each deliverable is based on vendor-specific objective evidence (VSOE) if available, third-party evidence if VSOE is not available, or estimated selling price if neither VSOE or third-party evidence is available. ASU 2009-13 is effective for revenue arrangements entered into in fiscal years beginning on or after June 15, 2010. We are currently evaluating the impact the adoption of ASU 2009-13 will have, if any, on our results of operations and financial position.

In January 2010, the Financial Accounting Standards Board issued Accounting Standards Update 2010-03 (ASU 2010-03), “Oil and Gas Reserve Estimation and Disclosures.” The update provides an amendment to Accounting Standards Codification 932 (ASC 932), “Extractive Activities – Oil and Gas,” that expands the definition of oil- and gas-producing activities and requires disclosures of reserve quantities and standardized measure of cash flows for equity-method investments that have significant oil- and gas-producing activities. ASU 2010-03 is effective for annual reporting periods ending on or after December 31, 2009. ASU 2010-03 allows an entity that becomes subject to the disclosure requirements of ASC 932 due to the change to the definition of significant oil- and gas-producing activities to apply the disclosure provisions of ASC 932 in annual periods beginning after December 31, 2009. As such, we have elected to defer the application of ASU 2010-03 until our annual reporting period ended December 31, 2010. We are currently evaluating the impact the adoption of ASU 2010-03 will have on our disclosures within our financial statements.

Item 3.		Quantitative and Qualitative Disclosures about Market Risk

We are exposed to market risk from changes in foreign currency exchange, interest rates, equity prices, and oil and gas prices as discussed below.

Foreign Currency Exchange Rates

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

We do not hold derivatives for trading purposes or use derivatives with complex features. Assets and liabilities of our subsidiaries in the United Kingdom and Europe are translated at end of period exchange rates, while income and expense are translated at average rates for the period. Translation gains and losses are reported as the foreign currency translation component of accumulated other comprehensive loss in stockholders’ equity.

When we believe prudent, we enter into forward foreign exchange contracts to hedge the impact of foreign currency fluctuations. The forward foreign exchange contracts we enter into generally have maturities ranging from one to eighteen months. We do not enter into forward foreign exchange contracts for trading purposes. As of September 30, 2010, we had no outstanding foreign currency forward contracts.

Interest Rate Risk

At September 30, 2010, our debt (exclusive of discounts), was comprised of the following (in thousands):

		Fixed				Variable
		Rate Debt				Rate Debt
Bank revolving credit facility due 2014 ^		$	—			$	193,500
6.875% Senior notes due 2014 *			150,000				150,000
1.5% Senior exchangeable notes due 2026			400,000				—
U.S. Government guaranteed long-term financing due 2027			13,761				—
Total Debt		$	563,761			$	343,500

Based on the amount of this debt outstanding at September 30, 2010, a 10% increase in the variable interest rate would increase our interest expense for the nine months ended September 30, 2010 by approximately $1.0 million, while a 10% decrease would decrease our interest expense by approximately $1.0 million.

Equity Price Risk

We have $400 million of 1.50% senior exchangeable notes due 2026. The notes are, subject to the occurrence of specified conditions, exchangeable for our common stock initially at an exchange price of $45.58 per share, which would result in an aggregate of approximately 8.8 million shares of common stock being issued upon exchange. We may redeem for cash all or any part of the notes on or after December 15, 2011 for 100% of the principal amount redeemed. The holders may require us to repurchase for cash all or any portion of the notes on December 15, 2011, December 15, 2016 and December 15, 2021 for 100% of the principal amount of notes to be purchased plus any accrued and unpaid interest. The notes do not contain any restrictive financial covenants.

Each $1,000 of principal amount of the notes is initially exchangeable into 21.9414 shares of our common stock, subject to adjustment upon the occurrence of specified events. Holders of the notes may exchange their notes prior to maturity only if (1) the price of our common stock reaches 135% of the applicable exchange rate during certain periods of time specified in the notes; (2) specified corporate transactions occur; (3) the notes have been called for redemption; or (4) the trading price of the notes falls below a certain threshold. In addition, in the event of a fundamental change in our corporate ownership or structure, the holders may require us to repurchase all or any portion of the notes for 100% of the principal amount.

We also have agreements with affiliates of the initial purchasers to purchase call options and sell warrants of our common stock. We may exercise the call options at any time to acquire approximately 8.8 million shares of our common stock at a strike price of $45.58 per share. The owners of the warrants may exercise their warrants to purchase from us approximately 8.8 million shares of our common stock at a price of $59.42 per share, subject to certain anti-dilution and other customary adjustments. The warrants may be settled in cash, in shares or in a combination of cash and shares, at our option. Lehman Brothers OTC Derivatives, Inc. (LBOTC) is the counterparty to 50% of our call option and warrant transactions. We continue to carefully monitor the developments affecting LBOTC. Although we may not be able to retain the benefit of the call option due to LBOTC’s bankruptcy, we do not expect that there will be a material impact, if any, on the financial statements or results of operations. The call option and warrant transactions described above do not affect the terms of the outstanding exchangeable notes.

Commodity Price Risk

Our revenues, profitability and future rate of growth significantly depend 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.

For additional discussion of the notes, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” in Part I, Item 2 above.

Item 4.		Controls and Procedures

	a.		Evaluation of disclosure control and procedures. As of the end of the period covered by this quarterly report on Form 10-Q, our Chief Executive Officer and Chief Financial Officer have concluded, based on their evaluation, that our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) 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 accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures and is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
	b.		Changes in internal control. There has been no change in our internal control over financial reporting that occurred during the three months ended September 30, 2010, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1A. Risk Factors

Except as set forth below, there have been no material changes to the risk factors previously disclosed in our Form 10-K for the year ended December 31, 2009. For additional information on risk factors, refer to Item 1A. Risk Factors of Part I of our annual report on Form 10-K for the year ended December 31, 2009.

The Deepwater Horizon incident could have a lingering significant impact on exploration and production activities in United States coastal waters that could adversely affect demand for our services and equipment.

As an oil and gas service company, the success and profitability of our operations in the United States are dependent on the level of drilling and exploration activity in the Gulf of Mexico. Revenue generated from our Gulf of Mexico market area was approximately $516.3 million and $700.4 million for the nine month periods ended September 30, 2010 and 2009, respectively.

The April 2010 catastrophic explosion of the Deepwater Horizon, the related oil spill in the Gulf of Mexico and the U.S. government’s response to these events has significantly and adversely disrupted oil and gas exploration activities in the Gulf of Mexico. The President of the United States appointed a commission to study the causes of the catastrophe for the purpose of recommending legislative or regulatory measures that should be taken in order to minimize the possibility of a reoccurrence of similar disasters. Shortly after the explosion, the United States government imposed a moratorium effectively suspending all deepwater drilling activity in the Gulf of Mexico which was just recently lifted. Although the moratorium did not suspend drilling activity in the shallow waters of the Gulf of Mexico, new safety and permitting requirements have been imposed on shallow water operators and few new drilling permits have been issued to shallow water operators since the Deepwater Horizon explosion. Additionally, various bills are being considered by Congress which, if enacted, could either significantly increase the costs of conducting drilling and exploration activities in the Gulf of Mexico, particularly in deep waters, or possibly drive a substantial portion of drilling and operation activity out of the Gulf of Mexico.

Although the deepwater drilling moratorium has been lifted, the return of demand for our products and services to pre-moratorium levels remains uncertain. Among the uncertainties that confront the industry are whether Congress will repeal the $75 million cap for non-reclamation liabilities under the Oil Pollution Act of 1990, whether insurance will continue to be available at a reasonable cost and with reasonable policy limits to support drilling and exploration activity in the Gulf of Mexico, whether permits for drilling and other oilfield service activities will be issued and at what rate, and whether the overall legislative and regulatory response to the disaster will discourage investment in oil and gas exploration in the Gulf of Mexico. Although the eventual outcome of these uncertainties is currently unknown, any one or more of them could further reduce demand for our services and equipment and adversely affect our operations in the Gulf of Mexico. However, until the ultimate regulatory response to this catastrophe becomes more certain, we cannot accurately predict the extent of the impact of this event on our customers and similarly, the longer term impact the catastrophe may have on our business and operations. Any regulatory response that has the effect of materially curtailing drilling and exploration activity in the Gulf of Mexico will ultimately adversely affect our operations in the Gulf of Mexico.

The following risk factors included in Item 1A. Risk Factors of Part I of our annual report on Form 10-K for the year ended December 31, 2009, have been updated:

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 the following:

	•		fires;
	•		explosions, blowouts and cratering;
	•		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.

These risks affect our provision of oilfield services and equipment, as well as our oil and gas operations. Our liftboats and marine vessels are also subject to operating risks such as marine disasters, adverse weather conditions, collisions and navigation errors.

The realization of any of these risks could result in catastrophic events causing personal injury, loss of life, damage to or destruction of wells, production facilities or other property or equipment, or damages to the environment, which could lead to claims against us for substantial damages. A catastrophic event could also subject us to cleanup obligations, regulatory investigation, penalties or suspension of operations. 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 generally without limitation. Realization of any of the foregoing by our equity-method investments engaged in oil and gas production could result in significant impairment of our related equity-method investment balances.

As a result of indemnification obligations contained in most of our customer contracts, we may also be required to indemnify our customers for any damages sustained by our employees or equipment, regardless of whether those damages were caused by us.

We maintain several types of insurance to cover liabilities arising from our operations. These policies include primary and excess umbrella liability policies with limits of $100 million dollars per occurrence, including sudden and accidental pollution incidents. We also maintain property insurance on our physical assets, including marine vessels and operating equipment and platforms and wells. The cost of many of the types of insurance coverage maintained for our oil and gas operations has increased significantly due to losses as a result of hurricanes that occurred in the Gulf of Mexico in recent years and resulted in the retention of significant additional risk of loss by us and our equity-method investments, primarily through higher insurance deductibles. Also, most of these property insurance policies now have annual aggregate limits, rather than occurrence-based limits, for named storm damages and significantly higher deductibles for wind damage. 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.

The frequency and severity of incidents relating to our operating risks affect our operating costs, insurability, earnings from our equity-method investments, and relationships with customers, employees and regulators. Any increase in the frequency or severity of such incidents, or the general level of compensation and damage awards with respect to such incidents, could adversely affect our ability to obtain insurance or projects from oil and gas companies. Also, any significant uninsured losses could have a material adverse effect on our financial position, results of operations and cash flows.

We are susceptible to adverse weather conditions in the Gulf of Mexico.

Certain areas in and near the Gulf of Mexico experience hurricanes and other extreme weather conditions on a relatively frequent basis. Substantially all of our assets offshore and along the Gulf of Mexico are susceptible to damage or total loss by these storms. Although we maintain insurance on our properties, due to the significant losses incurred as a consequence of the hurricanes that occurred in the Gulf of Mexico in recent years, these coverages are not comparable with that of prior years. For instance, since 2006, our insurance policies now have an annual aggregate limit, rather than an occurrence limit. Also, our deductible for wind damage versus non-wind events is between five and ten times higher. Thus, we are at a greater risk of loss due to severe weather conditions. Any significant uninsured losses could have a material adverse effect on our financial position, results of operations and cash flows.

Damage to our equipment caused by high winds and turbulent seas could cause us to curtail or suspend service operations for significant periods of time until damage can be assessed and repaired. Moreover, even if we do not experience direct damage from any of these storms, we may experience disruptions in our operations because customers may curtail or suspend their development activities due to damage to their platforms, pipelines and other related facilities. We do not maintain business interruption insurance that would protect us in these events.

Item 6. Exhibits

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

	3.1		Composite Certificate of Incorporation of the Company (incorporated herein by reference to Exhibit 3.1 to the Company’s Form 10-Q filed on August 7, 2009).
	3.2		Amended and Restated Bylaws of the Company (incorporated herein by reference to Exhibit 3.1 to the Company’s Form 8-K filed on September 12, 2007).
	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.
	101.INX**		XBRL Instance Document
	101.SCH**		XBRL Taxonomy Extension Schema Document
	101.CAL**		XBRL Taxonomy Extension Calculation Linkbase Document
	101.LAB**		XBRL Taxonomy Extension Label Linkbase Document
	101.PRE**		XBRL Taxonomy Extension Presentation Linkbase Document

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.