UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

SUPERIOR ENERGY SERVICES, INC.

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

	Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
	Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes þ No o
	The number of shares of the registrant’s common stock outstanding on April 29, 2005 was 77,681,947.

1

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Quarterly Report on Form 10-Q for
the Quarterly Period Ended March 31, 2005

TABLE OF CONTENTS

2

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

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

See accompanying notes to consolidated financial statements.

3

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES
Condensed Consolidated Statements of Operations
Three Months Ended March 31, 2005 and 2004
(in thousands, except per share data)
(unaudited)

See accompanying notes to consolidated financial statements.

4

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

See accompanying notes to consolidated financial statements.

5

SUPERIOR ENERGY SERVICES, INC. AND SUBSIDIARIES

(1) Basis of Presentation

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

The financial information of Superior Energy Services, Inc. and subsidiaries (the Company) for the three months ended March 31, 2005 and 2004 has not been audited. However, in the opinion of management, all adjustments (which include only normal recurring adjustments) necessary to present fairly the results of operations for the periods presented have been included therein. The results of operations for the first three months of the year are not necessarily indicative of the results of operations that might be expected for the entire year. Certain previously reported amounts have been reclassified to conform to the 2005 presentation.

(2) Stock Based Compensation

The Company accounts for its stock based compensation under the principles prescribed by the Accounting Principles Board’s (Opinion No. 25), “Accounting for Stock Issued to Employees.” However, Statement of Financial Accounting Standards No. 123 (FAS No. 123), “Accounting for Stock-Based Compensation” permits the continued use of the intrinsic-value based method prescribed by Opinion No. 25 but requires additional disclosures, including pro forma calculations of earnings and net earnings per share as if the fair value method of accounting prescribed by FAS No. 123 had been applied. No stock based compensation costs are reflected in net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of the grant. Stock compensation costs from the grant of restricted stock units are expensed as incurred. The pro forma data presented below is not representative of the effects on reported amounts for future years (amounts are in thousands, except per share amounts):

6

(3) Earnings per Share

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

(4) Acquisitions

In 2004, the Company’s wholly-owned subsidiary, SPN Resources, LLC, acquired additional oil and gas properties through the acquisition of interests in 19 offshore Gulf of Mexico leases. Under the terms of the transactions, the Company acquired the properties and assumed the decommissioning liabilities. In the aggregate, the Company paid $10.7 million cash, net of amounts received. The Company recorded decommissioning liabilities of approximately $83.0 million and notes and other receivables of approximately $12.5 million, and oil and gas producing assets were recorded at their estimated fair value of approximately $81.2 million.

In 2004, the Company acquired two businesses for an aggregate of $2.8 million in cash consideration in order to enhance the products and services offered by its rental tools segment and well intervention segment. These acquisitions were accounted for as purchases and the acquired assets and liabilities were valued at their estimated fair value. The purchase price allocated to net assets was approximately $1.0 million in the aggregate, and the excess purchase price over the fair value of net assets of approximately $1.8 million was allocated to goodwill. The results of operations have been included from the respective acquisition dates.

Most of the Company’s business acquisitions have involved additional contingent consideration based upon a multiple of the acquired companies’ respective average earnings before interest, income taxes, depreciation and

7

amortization expense (EBITDA) over a three-year period from the respective date of acquisition. While the amounts of the additional consideration payable depend upon the acquired company’s operating performance and are difficult to predict accurately, the maximum additional consideration payable for the Company’s remaining acquisitions is approximately $2.8 million, and will be determined and payable through 2007. These amounts are not classified as liabilities under generally accepted accounting principles and are not reflected in the Company’s financial statements until the amounts are fixed and determinable. The Company does not have any other financing arrangements that are not required under generally accepted accounting principles to be reflected in its financial statements. When the amounts are determined, they are capitalized as part of the purchase price of the related acquisition. In the three months ended March 31, 2005, the Company paid additional consideration of $5.3 million as a result of a prior acquisition which had been capitalized and accrued in 2004.

(5) Segment Information

Business Segments

In 2004, the Company modified its segment disclosure by separating its oil and gas operations from the well intervention segment. This change better reflects the impact of the Company’s increased oil and gas operations and service work created for the other segments, as well as how Company management evaluates the Company’s results of operations. The Company’s reportable segments are as follows: well intervention, rental tools, marine, other oilfield services and oil and gas. The first four segments offer products and services within the oilfield services industry. The well intervention segment provides plug and abandonment services, coiled tubing services, well pumping and stimulation services, data acquisition services, gas lift services, electric wireline services, hydraulic drilling and workover services, well control services, engineering support, technical analysis and mechanical wireline services that perform a variety of ongoing maintenance and repairs to producing wells, as well as modifications to enhance the production capacity and life span of the well. The rental tools segment rents and sells specialized equipment for use with onshore and offshore oil and gas well drilling, completion, production and workover activities. The marine segment operates liftboats for production service activities, as well as oil and gas production facility maintenance, construction operations and platform removals. The other oilfield services segment provides contract operations and maintenance services, transportation and logistics services, offshore oil and gas cleaning services, oilfield waste treatment services, dockside cleaning of items, including supply boats, cutting boxes, and process equipment, and manufactures and sells drilling instrumentation and oil spill containment equipment. The oil and gas segment acquires mature oil and gas properties through SPN Resources, LLC and produces and sells any remaining economic oil and gas reserves prior to the Company’s other segments providing decommissioning services. Oil and gas eliminations represent products and services provided to the oil and gas segment by the Company’s four other segments.

Prior period information has been reclassified to reflect the Company’s current segments. Summarized financial information concerning the Company’s segments for the three months ended March 31, 2005 and 2004 is shown in the following tables (in thousands):

8

Three Months Ended March 31, 2005

Three Months Ended March 31, 2004

Identifiable Assets

Geographic Segments

The Company attributes revenue to countries based on the location where services are performed or the destination of the sale of products. Long-lived assets consist primarily of property, plant and equipment and are attributed to the United States or other countries based on the physical location of the asset at the end of a period. The Company’s information by geographic area is as follows (amounts in thousands):

9

(6) Debt

The Company has a bank credit facility consisting of term loans in an aggregate amount of $35.8 million outstanding at March 31, 2005, and a revolving credit facility of $75 million, none of which was outstanding at March 31, 2005. The term loans require principal payments of $2.8 million each quarter through June 30, 2008. Any balance outstanding on the revolving credit facility is due on August 13, 2006. The credit facility bears interest at a LIBOR rate plus margins that depend on the Company’s leverage ratio. Indebtedness under the credit facility is secured by substantially all of the Company’s assets, including the pledge of the stock of the Company’s principal subsidiaries. The credit facility contains customary events of default and requires that the Company satisfy various financial covenants. It also limits the Company’s capital expenditures, its ability to pay dividends or make other distributions, make acquisitions, make changes to the Company’s capital structure, create liens, incur additional indebtedness or assume additional decommissioning liabilities. During the first quarter, the Company amended its bank credit facility to permit it to incur additional secured indebtedness of up to $5.0 million. The Company also has letters of credit outstanding of approximately $7.1 million at March 31, 2005, which reduce the borrowing availability under its revolving credit facility. At March 31, 2005, the Company was in compliance with all such covenants.

The Company has $18.2 million outstanding in U. S. Government guaranteed long-term financing under Title XI of the Merchant Marine Act of 1936, which is administered by the Maritime Administration (MARAD), for two 245-foot class liftboats. The debt bears interest at 6.45% per annum and is payable in equal semi-annual installments of $405,000, on every June 3rd and December 3rd through June 3, 2027. The Company’s obligations are secured by mortgages on the two liftboats. In accordance with this agreement, the Company is required to comply with certain covenants and restrictions, including the maintenance of minimum net worth and debt-to-equity requirements. At March 31, 2005, the Company was in compliance with all such covenants. This long-term financing ranks equally with the bank credit facility.

The Company also has outstanding $200 million of 8 7/8% unsecured senior notes due 2011. The indenture governing the notes requires semi-annual interest payments, on every May 15^th and November 15^th through the maturity date of May 15, 2011. The indenture governing the senior notes contains certain covenants that, among other things, prevent the Company from incurring additional debt, paying dividends or making other distributions, unless its ratio of cash flow to interest expense is at least 2.25 to 1, except that the Company may incur additional debt in addition to the senior notes in an amount equal to 30% of its net tangible assets as defined, which was approximately $184 million at March 31, 2005. The indenture also contains covenants that restrict the Company’s ability to create certain liens, sell assets or enter into certain mergers or acquisitions. At March 31, 2005, the Company was in compliance with all such covenants.

(7) Hedging Activities

The Company enters into hedging transactions with major financial institutions to secure a commodity price for a portion of future production and to reduce its exposure to fluctuations in the price of oil. The Company does not enter into hedging transactions for trading purposes. Crude oil hedges are settled based on the average of the reported settlement prices for West Texas Intermediate crude on the New York Mercantile Exchange (NYMEX) for each month. The Company had no natural gas hedges as of March 31, 2005. The Company uses financially-settled crude oil swaps and zero-cost collars that provide floor and ceiling prices with varying upside price participation. The Company’s swaps and zero-cost collars are designated and accounted for as cash flow hedges.

With a financially-settled swap, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the hedged price for the transaction, and the Company is required to make a

10

payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. With a zero-cost collar, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price of the collar, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar. The Company recognizes the fair value of all derivative instruments as assets or liabilities on the balance sheet. Changes in the fair value of cash flow hedges are recognized, to the extent the hedge is effective, in other comprehensive income until the hedged item is settled and recorded in revenue. For the three months ended March 31, 2005, hedging settlement payments reduced oil revenues by approximately $848,000. The Company reduced revenue by approximately $206,000 due to hedge ineffectiveness.

The Company had the following hedging contracts as of March 31, 2005:

Based on the estimated fair values of the derivative contracts at March 31, 2005, the Company expects to reclassify net losses of approximately $6.6 million, net of taxes, into earnings related to the derivative contracts during the next twelve months; however, actual gains or losses recognized may differ materially.

(8) Decommissioning Liabilities

The Company records estimated future decommissioning liabilities related to its oil and gas producing properties pursuant to the provisions of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (FAS No. 143). FAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation (decommissioning liabilities) in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. Subsequent to initial measurement, the decommissioning liability is required to be accreted each period to present value. The Company’s decommissioning liabilities consist of costs related to the plugging of wells, the removal of facilities and equipment and site restoration on oil and gas properties.

The Company estimates the cost that would be incurred if it contracted an unaffiliated third party to plug and abandon wells, abandon the pipelines, decommission and remove the platforms and pipelines and restore the sites of its oil and gas properties, and uses that estimate to record its proportionate share of the decommissioning liability. In estimating the decommissioning liability, the Company performs detailed estimating procedures, analysis and engineering studies. Whenever practical, the Company utilizes its own equipment and labor services to perform well abandonment and decommissioning work. When the Company performs these services, all recorded intercompany revenues are eliminated in the consolidated financial statements. The recorded decommissioning liability associated with a specific property is fully extinguished when the property is abandoned. The recorded liability is first reduced by all cash expenses incurred to abandon and decommission the property. If the recorded liability exceeds (or is less than) the Company’s out-of-pocket costs, then the difference is reported as income (or loss) within revenue during the period in which the work is performed. The Company continually reviews the adequacy of its decommissioning liabilities. The timing and amounts of these cash flows are estimates, and changes to these estimates may result in additional liabilities recorded, which in turn would increase the carrying values of the related oil and gas properties. The following table summarizes the activity for the Company’s decommissioning liabilities for the three months ended March 31, 2005 and 2004 (amounts in thousands):

11

(9) Notes Receivable

Notes receivable consist primarily of commitments from the sellers of oil and gas properties towards the abandonment of the acquired properties. Pursuant to the agreement between the Company and a seller, the Company will invoice the seller agreed upon amounts during the course of decommissioning (abandonment and structure removal). These receivables are recorded at present value, and the related discounts are amortized to interest income, based on the expected timing of the decommissionings.

(10) Other Comprehensive Income

The following tables reconcile the change in accumulated other comprehensive income (loss) for the three months ended March 31, 2005 and 2004 (amounts in thousands):

12

(11) Commitments and Contingencies

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

(12) Accounting Pronouncements

In December 2004, the Financial Accounting Standards Board revised its Statement of Financial Accounting Standards No. 123 (FAS No. 123R), “Accounting for Stock Based Compensation.” The revision establishes standards for the accounting of transactions in which an entity exchanges its equity instruments for goods or services, particularly transactions in which an entity obtains employee services in share-based payment transactions. The revised statement requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. That cost is to be recognized over the period during which the employee is required to provide service in exchange for the award. Changes in fair value during the requisite service period are to be recognized as compensation cost over that period. In addition, the revised statement amends Statement of Financial Accounting Standards No. 95, “Statement of Cash Flows,” to require that excess tax benefits be reported as a financing cash flow rather than as a reduction of taxes paid. The Company plans to adopt FAS No. 123R effective January 1, 2006. The Company is currently assessing the expected impact on its consolidated 2006 financial statements.

13

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

Forward-Looking Statements

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

Executive Summary

We posted our highest ever quarterly revenue, operating income and net income due to increased demand for our production-related services in the shallow water Gulf of Mexico market, increased demand for our rental tools and increased oil and gas production.

Shallow water Gulf of Mexico production-related activity increased as compared to the first and fourth quarters of 2004. Activity increased in our coiled tubing, electric line, mechanical wireline and pumping and stimulation businesses due to more production-related work performed for our traditional customers and subsidiary, SPN Resources, LLC. We benefited from our strategy of increasing utilization through our ownership of mature properties. Work on our own properties accounted for 31% of the utilization of our well services crews within our well intervention segment, as compared to 29% and 21% of their utilization for the first and fourth quarters of 2004, respectively. Improvements in these production-related businesses were more than offset by decreased activity for our well control services. As anticipated, results from the well control business were not as strong as the fourth quarter because of less work associated with a large-scale well control project in Egypt.

We continued to increase the scope of our rental tools operations internationally in the North Sea and West Africa, and domestically in Oklahoma, Texas and Wyoming. In addition, deepwater Gulf of Mexico drilling and completion projects resumed following Hurricane Ivan-related downtime. Rentals of drill pipe, stabilizers, connecting iron and ancillary tubular products increased due to increased activity in these areas. We saw a significant increase in our plant services, which consist of bolting and machining services provided to refineries and chemical plants. Demand for these services typically increases during the winter months as refineries and plants perform maintenance work.

Oil and gas production from our largest producing property – South Pass 60 – returned following several months of maintenance and repair work to facilities following damage caused by Hurricane Ivan in September 2004. We also benefited from our first full quarter of production from West Delta 79/86, which was acquired in December 2004. First quarter 2005 oil and gas production was approximately 600,500 net barrels of oil equivalent (“net boe”) as compared to 289,400 net boe in the fourth quarter of 2004.

14

Revenue was down slightly in our marine segment from the fourth quarter of 2004. Our average daily revenue, inclusive of subsistence revenue, was approximately $220,000 in the first quarter of 2005, down from $222,300 in the fourth quarter of 2004. Although dayrates and utilization were flat to slightly higher in most liftboat classes, we were without the services of our 230-ft. class Superior Champion liftboat for almost two months due to leg damage. Despite the lower revenue, operating income increased as compared to the fourth quarter of 2004 because of less maintenance and shipyard expenses.

Our other oilfield services segment achieved higher revenue as compared to the fourth quarter due in part to increased volumes of treated and disposed non-hazardous oilfield waste and increased demand for offshore supplemental labor and property management services. Operating income was lower sequentially due to competitive pricing for environmental services and the increase in lower margin property management services.

Comparison of the Results of Operations for the Three Months Ended March 31, 2005 and 2004

For the three months ended March 31, 2005, our revenues were $173.2 million, resulting in net income of $17.2 million or $0.22 diluted earnings per share. For the three months ended March 31, 2004, revenues were $116.5 million and net income was $3.6 million. Diluted earnings per share were $0.05 for the same period. We experienced higher revenue and gross margin in all our segments.

The following table compares our operating results for the three months ended March 31, 2005 and 2004. Gross margin is calculated by subtracting cost of services from revenue for each of our five business segments. Oil and gas eliminations represent products and services provided to the oil and gas segment by the Company’s four other segments.

The following discussion analyzes our results on a segment basis.

Well Intervention Segment

Revenue for our well intervention segment was $58.3 million for the three months ended March 31, 2005, as compared to $40.6 million for the same period in 2004. This segment’s gross margin percentage increased to 45% for the three months ended March 31, 2005 from 41% for the same period of 2004. We experienced higher revenue for almost all of our services as production-related activity improved in the Gulf of Mexico. This increase in activity levels also contributed to the improvement of the gross margin percentage.

Rental Tools Segment

Revenue for our rental tools segment for the three months ended March 31, 2005 was $52.6 million, a 36% increase over the same period in 2004. The gross margin percentage remained unchanged at 67% for the three months ended March 31, 2005 and 2004. The increase in revenue is primarily due to increased activity in the Gulf of Mexico, as well as our international and domestic expansion efforts.

15

Marine Segment

Our marine segment revenue for the three months ended March 31, 2005 increased 45% over the same period in 2004 to $19.8 million. The gross margin percentage for the three months ended March 31, 2005 increased to 40% from 15% for the same period in 2004. The increases in revenue and gross margin percentage were caused by increases in the fleet’s dayrates and utilization. The fleet’s average dayrate increased 22% to approximately $6,950 in the first quarter of 2005 from $5,700 in the first quarter of 2004. The fleet’s average utilization also increased to approximately 77% for the first quarter of 2005 from 64% in the same period in 2004.

Other Oilfield Services Segment

Other oilfield services revenue for the three months ended March 31, 2005 was $21.8 million, a 10% increase over the $19.9 million in revenue for the same period in 2004. The gross margin percentage increased to 20% in the three months ended March 31, 2005 from 14% in the same period in 2004. The revenue increase is primarily due to increased demand for our field management services. The increase in the segment’s gross margin percentage is due to this increased demand as well as cost saving efforts in our waste disposal services.

Oil and Gas Segment

Oil and gas revenues were $26.0 million in the three months ended March 31, 2005 as compared to $4.7 million in the same period of 2004. The increase in revenue is primarily the result of production from South Pass 60, which was acquired in July 2004, and production from West Delta 79/86, which was acquired in December 2004. The first quarter of 2005 is the first full quarter of production from both of these acquisitions. In the first quarter of 2005, production was approximately 600,500 net boe as compared to approximately 131,100 net boe in the first quarter of 2004. The gross margin percentage increased to 51% in the three months ended March 31, 2005 from 48% in the same period of 2004. This increase is primarily the result of higher commodity prices.

Depreciation, Depletion, Amortization and Accretion

Depreciation, depletion, amortization and accretion increased to $22.4 million in the three months ended March 31, 2005 from $14.8 million in the same period in 2004. The increase is primarily a result of depletion and accretion related to our oil and gas properties, as well as, our 2004 capital expenditures.

General and Administrative

General and administrative expenses increased to $32.4 million for the three months ended March 31, 2005 from $24.2 million for the same period in 2004. The increase is primarily the result of our internal growth, both domestic and international expansion and our oil and gas acquisitions. However, general and administrative expenses decreased to 19% of revenue for the three months ended March 31, 2005 from 21% for the same period in 2004.

Liquidity and Capital Resources

In the three months ended March 31, 2005, we generated net cash from operating activities of $33.3 million as compared to $26.2 million in the same period of 2004. Our primary liquidity needs are for working capital, capital expenditures, debt service and acquisitions. Our primary sources of liquidity are cash flows from operations and borrowings under our revolving credit facility. We had cash and cash equivalents of $14.6 million at March 31, 2005 compared to $15.3 million at December 31, 2004.

We made $30.2 million of capital expenditures during the three months ended March 31, 2005, of which approximately $18.0 million was used to expand and maintain our rental tool equipment inventory. We also made $5.8 million of capital expenditures in our oil and gas segment and $5.4 million of capital expenditures to expand and maintain the asset base of our well intervention, marine, and other oilfield services. In addition, we made $1.0 million of capital expenditures on construction and improvements to our facilities.

We contracted to construct a 880-ton derrick barge to support our plugging and abandonment operations on the Outer Continental Shelf. The contracts are for the construction of a 350-foot barge and crane for a price of

16

approximately $22 million. This amount does not include any change orders, barge outfitting or mobilization costs. We expect the barge to be available in the Gulf of Mexico late in the third quarter of 2006. We intend to utilize it to remove platforms and structures owned by our subsidiary, SPN Resources, LLC, and compete in the Gulf of Mexico construction market for both installation and removal projects. In the first quarter of 2005, a progress payment was made on the crane of $2.7 million.

We currently believe that we will make approximately $60 million of capital expenditures, excluding acquisitions and targeted asset purchases, during the remaining nine months of 2005 primarily to further expand our rental tool asset base and perform workovers on SPN Resources oil and gas properties. We believe that our current working capital, cash generated from our operations and availability under our revolving credit facility will provide sufficient funds for our identified capital projects.

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

We have a bank credit facility consisting of term loans in an aggregate amount of $35.8 million outstanding at March 31, 2005 and a revolving credit facility of $75 million, none of which was outstanding at March 31, 2005. As of April 29, 2005, these balances were unchanged and the weighted average interest rate under the credit facility was 5.4% per annum. Indebtedness under the credit facility is secured by substantially all of our assets, including the pledge of the stock of our principal subsidiaries. The credit facility contains customary events of default and requires that we satisfy various financial covenants. It also limits our capital expenditures, our ability to pay dividends or make other distributions, make acquisitions, make changes to our capital structure, create liens, incur additional indebtedness or assume additional decommissioning liabilities.

We have $18.2 million outstanding at March 31, 2005 in U. S. Government guaranteed long-term financing under Title XI of the Merchant Marine Act of 1936, which is administered by the Maritime Administration (MARAD), for two 245-foot class liftboats. This debt bears an interest rate of 6.45% per annum and is payable in equal semi-annual installments of $405,000 on every June 3^rd and December 3^rd through June 3, 2027. Our obligations are secured by mortgages on the two liftboats. This MARAD financing also requires that we comply with certain covenants and restrictions, including the maintenance of minimum net worth and debt-to-equity requirements.

We also have outstanding $200 million of 8 7/8% senior notes due 2011. The indenture governing the senior notes requires semi-annual interest payments on every May 15^th and November 15^th through the maturity date of May 15, 2011. The indenture governing the senior notes contains certain covenants that, among other things, prevent us from incurring additional debt, paying dividends or making other distributions, unless our ratio of cash flow to interest expense is at least 2.25 to 1, except that we may incur debt in addition to the senior notes in an amount equal to 30% of our net tangible assets, which was approximately $184 million at March 31, 2005. The indenture also contains covenants that restrict our ability to create certain liens, sell assets or enter into certain mergers or acquisitions.

The following table summarizes our contractual cash obligations and commercial commitments at March 31, 2005 (amounts in thousands) for our long-term debt (including estimated interest payments), decommissioning liabilities, operating leases and contractual obligations. The decommissioning liability amounts do not give any effect to our contractual right to receive amounts from third parties, which is approximately $33.8 million, when decommissioning operations are performed. We do not have any other material obligations or commitments.

17

We have no off-balance sheet arrangements other than our potential additional consideration that may be payable as a result of our acquisitions. While the amounts of additional consideration payable depend upon the acquired company’s operating performance and are difficult to predict accurately, the maximum additional consideration payable for the Company’s remaining acquisitions will be approximately $2.8 million. These amounts are not classified as liabilities under generally accepted accounting principles and are not reflected in the Company’s financial statements until the amounts are fixed and determinable. When amounts are determined, they are capitalized as part of the purchase price of the related acquisition. We do not have any other financing arrangements that are not required under generally accepted accounting principles to be reflected in our financial statements.

We intend to continue implementing our growth strategy of increasing our scope of services through both internal growth and strategic acquisitions. We expect to continue to make the capital expenditures required to implement our growth strategy in amounts consistent with the amount of cash generated from operating activities, the availability of additional financing and our credit facility. Depending on the size of any future acquisitions, we may require additional equity or debt financing in excess of our current working capital and amounts available under our revolving credit facility.

New Accounting Pronouncements

In December 2004, the Financial Accounting Standards Board revised its Statement of Financial Accounting Standards No. 123 (FAS No. 123R), “Accounting for Stock Based Compensation.” The revision establishes standards for the accounting of transactions in which an entity exchanges its equity instruments for goods or services, particularly transactions in which an entity obtains employee services in share-based payment transactions. The revised statement requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. That cost is to be recognized over the period during which the employee is required to provide service in exchange for the award. Changes in fair value during the requisite service period are to be recognized as compensation cost over that period. In addition, the revised statement amends Statement of Financial Accounting Standards No. 95, “Statement of Cash Flows,” to require that excess tax benefits be reported as a financing cash flow rather than as a reduction of taxes paid. We plan to adopt FAS No. 123R effective January 1, 2006. We are currently assessing the expected impact on our consolidated 2006 financial statements.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

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

The Company uses derivative commodity instruments to manage commodity price risks associated with future oil and natural gas production. As of March 31, 2005, the Company had the following contracts in place:

18

The Company’s hedged volume as of March 31, 2005 was approximately 47% of its estimated production from proved reserves for the balance of the terms of the contracts. Had these contracts been terminated at March 31, 2005, the estimated loss would have been $9.9 million net of taxes.

The Company used a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of crude oil would have on the fair value of its existing derivative instruments. Based on the derivative instruments outstanding at March 31, 2005, a 10% increase in the underlying commodity price, would increase the estimated loss associated with the commodity derivative instrument by $3.5 million.

Interest Rate Risk

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

Item 4. Controls and Procedures

As of the end of the period covered by this quarterly report on Form 10-Q, our chief financial officer and chief executive officer have concluded, based on their evaluation, that our disclosure controls and procedures (as defined in rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended) are effective and designed to alert them to material information relating to the Company.

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

19

PART II. OTHER INFORMATION

Item 6. Exhibits

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

20

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.

21