Oil States International - 10-Q quarterly report FY

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.

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b — 2 of the Exchange Act).

     The accompanying unaudited consolidated financial statements of the Company and its wholly-owned subsidiaries have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission pertaining to interim financial information. Certain information in footnote disclosures normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles have been condensed or omitted pursuant to these rules and regulations. The unaudited financial statements included in this report reflect all the adjustments, consisting of normal recurring adjustments, which the Company considers necessary for a fair presentation of the results of operations for the interim periods covered and for the financial condition of the Company at the date of the interim balance sheet. Results for the interim periods are not necessarily indicative of results for the year.

     Preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosed amounts of contingent assets and liabilities and the reported amounts of revenues and expenses. If the underlying estimates and assumptions, upon which the financial statements are based, change in future periods, actual amounts may differ from those included in the accompanying consolidated condensed financial statements.

     From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (the “FASB”) which are adopted by the Company as of the specified effective date. Unless otherwise discussed, management believes the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s consolidated financial statements upon adoption.

     The financial statements included in this report should be read in conjunction with the Company’s audited financial statements and accompanying notes included in its Annual Report on Form 10-K for the year ended December 31, 2004.

     Additional information regarding selected balance sheet accounts is presented below (in thousands):

     In the fourth quarter of 2004, the FASB issued Statement No. 123 (revised 2004), or SFAS No. 123R, “Share-Based Payment,” which replaces Statement No. 123 “Accounting for Stock-Based Compensation,” and supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS No. 123R eliminates the alternative to use APB Opinion 25’s intrinsic value method of accounting that was provided in Statement No. 123 as originally issued. After a phase-in period for Statement No. 123R, pro forma disclosure will no longer be allowed. In the first quarter of 2005 the Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin No. 107 which provided further clarification on the implementation of SFAS No. 123R.

     Alternative phase-in methods are allowed under Statement No. 123R, which was to be effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. In April 2005, the Securities and Exchange Commission (“SEC”) adopted a rule that defers the required effective date of SFAS No. 123R. The SEC rule provides that SFAS No. 123R is now effective for registrants as of the beginning of the first fiscal year beginning after June 15, 2005. We are currently in the process of evaluating the impact of SFAS No. 123R on our consolidated condensed financial statements. We currently plan to adopt SFAS No. 123R on January 1, 2006.

     On February 1, 2005, the Company completed the acquisition of Elenburg Exploration Company, Inc. (Elenburg), a Wyoming based land drilling company for cash consideration of $21.3 million, including transaction costs, plus a note payable to the former owners of $0.8 million. Elenburg owns and operates 7 rigs which provide shallow land drilling services in Montana, Wyoming, Colorado, and Utah. The Elenburg acquisition allowed the Company to expand its drilling business into different geographic areas.

     Effective May 1, 2005 the Company acquired Stinger Wellhead Protection, Inc., certain affiliated companies and related intellectual property, (collectively, “Stinger”) for cash consideration of $77.9 million, net of cash acquired and including transaction costs, plus a note payable to the former owners of $5.0 million. Stinger provides wellhead isolation equipment and services through its 23 locations in the United States and Canada. Stinger’s patented equipment is utilized during pressure pumping operations and isolates the customers’ blow-out preventers or wellheads from the pressure and abrasion experienced during the fracturing process of an oil or gas well. In June 2005, the Company completed the acquisition of Stinger’s international operations for additional cash consideration of $6.1 million, net of cash acquired and including transaction costs. The Stinger international operations are conducted primarily in Central and South America. The Stinger acquisition expanded the Company’s rental tool and services capabilities, especially in the pressure pumping market.

     On June 2, 2005, the Company purchased Phillips Casing and Tubing, L.P. (Phillips) for cash consideration of $30.7 million, net of cash acquired and including transaction costs. Phillips distributes oil country tubular goods (OCTG), primarily carbon ERW (electronic resistance welded) pipe, from its facilities in Midland and Godley, Texas.

     On June 6, 2005, the Company acquired Noble Structures, Inc. into its well site services segment for cash consideration of $7.9 million, plus a note payable of $0.8 million. The acquisition expanded the Company’s accommodation manufacturing capabilities in Canada in order to meet increased demand for remote site facilities, principally in the oil sands region.

     The cash consideration paid for all of the Company’s acquisitions in the period was initially funded utilizing its existing bank credit facility and a $25 million bridge loan (See Note 6). Accounting for the acquisitions made in the period has not been finalized and is subject to adjustments during the purchase price allocation period, which is not expected to exceed a period of one year from the respective acquisition dates.

     Changes in the carrying amount of goodwill for the six month period ended June 30, 2005 are as follows (in thousands):

     As of June 30, 2005 and December 31, 2004, long-term debt consisted of the following (in thousands):

     On June 15, 2005, the Company sold $125 million aggregate principal amount of 2 3/8% contingent convertible senior notes due 2025 through a placement to qualified institutional buyers pursuant to the SEC’s Rule 144A. The Company granted the initial purchaser of the notes a 30-day option to purchase up to an additional $50 million aggregate principal amount of the notes. This option was exercised in July 2005 and an additional $50 million of the notes were sold at that time.

     The notes are senior unsecured obligations of the Company and bear interest at a rate of 2 3/8% per annum. The notes mature on July 1, 2025, and may not be redeemed by the Company prior to July 6, 2012. Holders of the notes may require the Company to repurchase some or all of the notes on July 1, 2012, 2015, and 2020. The notes provide for a net share settlement, and therefore may be convertible, under certain circumstances, into a combination of cash, up to the principal amount of the notes, and common stock of the company, if there is any excess above the principal amount of the notes, at an initial conversion price of $31.75 per share. Shares underlying the notes were not included in the calculation of diluted earnings per share because the Company’s share price as of June 30, 2005 was below the conversion price of $31.75. The terms of the notes require that the Company’s stock price in any quarter, for any period prior to July 1, 2023, be above 120% of the initial conversion price for at least 20 trading days in a defined period before the notes are convertible. As a result, there would be no conversion allowed under the terms of the notes at June 30, 2005.

     The Company utilized $30 million of the net proceeds of the offering on June 15, 2005 to repurchase 1,183,432 shares of its common stock and the remaining portion of the net proceeds to repay a $25.0 million bridge loan and to repay approximately $66.0 million of borrowings under its senior secured credit facility. Net proceeds of the additional notes sold in July 2005, totaling $48.5 million, were utilized to repay borrowings under the Company’s senior secured credit facility.

     On May 11, 2005 the Company borrowed $25 million under a bridge loan with a bank which was due in 2010. The loan was unsecured and was repaid in full on June 21, 2005. The average interest rate on this bridge loan for the period it was outstanding was 6.0%

     Comprehensive income for the three and six months ended June 30, 2005 and 2004 was as follows (in thousands):

     The Company has elected to follow Accounting Principles Board (“APB”) No. 25, “Accounting for Stock Issued to Employees,” for expense recognition purposes. As a result, the Company is obligated to provide the expanded disclosures required under SFAS No. 123, “Accounting for Stock Based Compensation,” and SFAS No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosure-an amendment of SFAS No. 123,” for stock-based compensation granted in 1998 and thereafter.

     The Company accounts for its employee stock-based compensation plan under APB Opinion No. 25 and its related interpretations. The Company is authorized to grant common stock based awards covering 7,700,000 shares of common stock under the 2001 Equity Participation Plan, as amended and restated (the Equity Participation Plan), to employees, consultants and directors with amounts, exercise prices and vesting schedules determined by the compensation committee of the Company’s Board of Directors. Any restricted stock awards issued under the Equity Participation Plan are considered compensatory in nature and the Company recognizes the fair value of the award as compensation expense over its vesting period. Since February 2001, all option grants have been priced at the closing price on the day of grant, vest 25% per year and have a life ranging from six to ten years. Because the exercise price of options granted under the Equity Participation Plan have been equal to the market price of the Company’s stock on the date of grant, no compensation expense related to this plan has been recorded. Had compensation expense for its Equity Participation Plan been determined consistent with SFAS No. 123 utilizing the fair value method, the Company’s net income and earnings per share for the three and six months ended June 30, 2005 and 2004, would have been as follows (in thousands, except per share amounts):

     Our primary deferred tax asset, which totaled approximately $12.5 million at December 31, 2004, is related to $35.8 million in available federal net operating loss carryforwards, or NOLs, as of that date. A valuation allowance of approximately $5.1 million was provided against the deferred tax asset associated with our NOLs at December 31, 2004. The NOLs will expire in varying amounts during the years 2010 through 2020 if they are not first used to offset taxable income generated by the Company. The Company’s ability to utilize a significant portion of the NOLs is currently limited under Section 382 of the Internal Revenue Code (“Code”) due to a change of control that occurred during 1995. A successive change in control was triggered in 2003 pursuant to Section 382 of the Code; however it did not significantly change the Company’s NOL utilization expectations.

     The Company’s income tax provision for the three months ended June 30, 2005 totaled $14.5 million, or 36.9% of pretax income compared to $8.0 million, or 39.8% of pretax income, for the three months ended June 30, 2004. The Company’s tax provision for the six months ended June 30, 2005 totaled $29.3 million, or 36.9% of pretax income, compared to $9.6 million, or 25.2% of pretax income, for the six month’s ended June 30, 2004. Our effective tax rate was lower in the first half of 2004 as a result of the recognition of a $5.4 million income tax benefit in the first quarter related to the partial reversal of the valuation allowance applied against NOLs which were recorded as of the prior year end.

     Based upon the loss limitation provisions of Section 382 of the Code, we expect to utilize approximately $8 million of our NOLs to offset taxable income generated by the Company during the tax year ended December 31, 2005.

     In accordance with SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information”, the Company has identified the following reportable segments: Offshore Products, Tubular Services, and Well Site Services. The Company’s reportable segments are strategic business units that offer different products and services. They are managed separately because each business requires different technology and marketing strategies. Most of the businesses were initially acquired as a unit, and the management at the time of the acquisition was retained. Subsequent acquisitions have been direct extensions to our business segments. Results of our Canadian business related to the provision of work force accommodations, catering and logistics services are seasonal with significant activity occurring in the peak winter drilling season.

     Financial information by industry segment for each of the three and six months periods ended June 30, 2005 and 2004 is summarized in the following table (in thousands):

     We are a party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning our commercial operations, products, employees and other matters, including occasional claims by individuals alleging exposure to hazardous materials as a result of our products or operations. Some of these claims relate to matters occurring prior to our acquisition of businesses, and some relate to businesses we have sold. In certain cases, we are entitled to indemnification from the sellers of businesses and in other cases, we have indemnified the buyers that purchased businesses from us. Although we can give no assurance about the outcome of pending legal and administrative proceedings and the effect such outcomes may have on us, we believe that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by indemnity or insurance, will not have a material adverse effect on our consolidated financial position, results of operations or liquidity.

     On February 18, 2005, the Company announced that it had conducted an internal investigation prompted by the discovery of over billings totaling approximately $400,000 by one of its subsidiaries to a government owned oil company in South America. The over billings were detected by the Company during routine financial review procedures, and appropriate financial statement adjustments were included in its previously reported fourth quarter 2004 results. The Company and independent counsel retained by the Company’s audit committee conducted separate investigations consisting of interviews and an examination of the facts and circumstances in this matter. The Company has voluntarily reported the results of its investigation to the Securities and Exchange Commission (the “SEC”) and will fully cooperate with any additional requests for information received from the SEC.

     This quarterly report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Exchange Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Actual results could differ materially from those projected in the forward-looking statements as a result of a number of important factors. For a discussion of important factors that could affect our results, please refer to “Item 1. Business” including the risk factors discussed therein and the financial statement line item discussions set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Form 10-K Annual Report for the year ended December 31, 2004 filed with the Securities and Exchange Commission on March 2, 2005 and Item 2., which follows. Except to the extent required by law, we undertake no obligation to update publicly any forward-looking statements, even if new information becomes available or other events occur in the future.

     You should read the following discussion and analysis together with our financial statements and the notes to those statements included elsewhere in this Quarterly Report on Form 10-Q.

     In our selection of critical accounting policies, our objective is to properly reflect our financial position and results of operations in each reporting period in a manner that will be understood by those who utilize our financial statements. Often we must use our judgment about uncertainties.

     There are several critical accounting policies that we have put into practice that have an important effect on our reported financial results. There have been no changes in these policies since the filing of our Annual Report on Form 10-K for the year ended December 31, 2004.

     We have contingent liabilities and future claims for which we have made estimates of the amount of the eventual cost to liquidate these liabilities or claims. These liabilities and claims sometimes involve threatened or actual litigation where damages have been quantified and we have made an assessment of our exposure and recorded a provision in our accounts to cover an expected loss. Other claims or liabilities have been estimated based on our experience in these matters and, when appropriate, the advice of outside counsel or other outside experts. Upon the ultimate resolution of these uncertainties, our future reported financial results will be impacted by the difference between our estimates and the actual amounts paid to settle a liability. Examples of areas where we have made important estimates of future liabilities include litigation, taxes, warranty claims, contract claims and discontinued operations.

     The determination of impairment on long-lived assets, including goodwill, is conducted when indicators of impairment are present. If such indicators were present, the determination of the amount of impairment would be based on our judgments as to the future operating cash flows to be generated from these assets throughout their estimated useful lives. Our industry is highly cyclical and our 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 value of these assets and, in periods of prolonged down cycles, may result in impairment charges.

     We recognize revenue and profit as work progresses on long-term, fixed price contracts using the percentage-of-completion method, which relies on estimates of total expected contract revenue and costs. We follow this method since reasonably dependable estimates of the revenue and costs applicable to various stages of a contract can be made. Recognized revenues and profit are subject to revisions as the contract progresses to completion. Revisions in profit estimates are charged to income or expense in the period in which the facts and circumstances that give rise to the revision become known. Provisions for estimated losses on uncompleted contracts are made in the period in which losses are determined.

     Our valuation allowances, especially related to potential bad debts in accounts receivable and to obsolescence or market value declines of inventory, involve reviews of underlying details of these assets, known trends in the marketplace and the application of historical factors that provide us with a basis for recording these allowances. If market conditions are less favorable than those projected by management, or if our historical experience is materially different from future experience, additional allowances may be required. We record a valuation allowance

to reduce our deferred tax assets to the amount that is more likely than not to be realized. While we have considered future taxable income and ongoing prudent and feasible tax planning strategies in assessing the need for the valuation allowance, in the event we were to determine that we would be able to realize our deferred tax assets in the future in excess of our net recorded amount, an adjustment to the deferred tax asset would increase income in the period such determination was made. Likewise, should we determine that we would not likely be able to realize all or part of our net deferred tax asset in the future, an adjustment to the deferred tax asset would be charged to expense in the period such determination was made. See also “Note 9 – Income Taxes” and “Tax Matters” herein.

     The selection of the useful lives of many of our assets requires the judgments of our operating personnel as to the length of these useful lives. Should our estimates be too long or short, we might eventually report a disproportionate number of losses or gains upon disposition or retirement of our long-lived assets. We believe our estimates of useful lives are appropriate.

     We provide a broad range of products and services to the oil and gas industry through our offshore products, tubular services and well site services business segments. Demand for our products and services is cyclical and substantially dependent upon activity levels in the oil and gas industry, particularly our customers’ willingness to spend capital on the exploration for and development of oil and gas reserves. Demand for our products and services by our customers is highly sensitive to current and expected oil and natural gas prices. Generally, our tubular services and well site services segments respond more rapidly to shorter-term movements in oil and natural gas prices than our offshore products segment. Our offshore products segment provides highly engineered and technically designed products for offshore oil and gas development and production systems and facilities. Sales of our offshore products and services depend upon the development of offshore production systems, repairs and upgrades of existing drilling rigs and construction of new drilling rigs. In this segment, we are particularly influenced by deepwater drilling and production activities, which are driven largely by our customers’ outlook for longer-term future oil prices. Through our tubular services segment, we distribute a broad range of casing and tubing. Sales of tubular products and services depend upon the overall level of drilling activity, the types of wells being drilled and the level of oil country tubular goods (“OCTG”) pricing. Historically, tubular services gross margins expand during periods of rising OCTG prices and contract during periods of decreasing OCTG prices. In our well site services business segment, we provide shallow land drilling services, hydraulic well control services, work force accommodations, catering and logistics services and rental tools. Demand for our drilling services is driven by land drilling activity in Texas, New Mexico, Ohio and in the Rocky Mountains area in the U.S. Our workover services are conducted in the U.S., South America, Africa, and the Middle East and are dependant upon the level of workover activity in those areas. Our rental tools and services depend primarily upon the level of drilling and workover activity in the U.S., Canada and Central and South America. Our accommodations segment is conducted primarily in Canada and its activity levels have historically been driven by oil and gas drilling and mining activities. In the past year, we have seen increased demand in our work force accommodation business as a result of oil sands development activities in Northern Alberta, Canada. We also support remote accommodations needs in the U.S. and on a worldwide basis.

     We have a diversified product and service offering which has exposure throughout the oil and gas cycle. Demand for our tubular services and well site services segments are highly correlated to changes in the rig count in the United States and Canada. The table below sets forth a summary of North American rig activity, as measured by Baker Hughes Incorporated, as of and for the periods indicated.

     The average North American rig count for the six months ended June 30, 2005 increased 177 rigs, or 11.8%, compared to the six months ended June 30, 2004. This overall increase in activity, while tempered somewhat by relatively flat activity levels in the U.S. Gulf of Mexico and Canada did contribute to increased revenues in our tubular services and well site services segments. Our well site services segment results for the first half of 2005 also benefited from capital spending, which aggregated $63.5 million in the twelve months ended June 30, 2005, the acquisition of Elenburg Exploration Company on February 1, 2005 for total consideration of $22.1 million, the acquisition of Stinger for total consideration of $89.0 million and the impact of activity levels and pricing gains in certain business lines. The Canadian rig count was relatively flat comparing the first half of 2004 and 2005; however, our operations also benefited from increased activity in support of oil sands development in the region. In the first half of 2005, approximately 47% of our accommodation revenues were derived from oil sands activity compared to 22% of accommodation revenues in the first half of 2004.

     During the first half of 2005, the results generated by our Canadian workforce accommodations, catering and logistics operations benefited from the strengthening of the Canadian currency. In the first half of 2005, the Canadian dollar was worth $0.81 in U.S. dollars compared to $0.75 in the first half of 2004.

     On May 11, 2004, our tubular services segment purchased the OCTG distribution business of Hunting Energy Services, L.P. (“Hunting”) for $47.2 million, including purchase price adjustments. On June 2, 2005 we acquired all of the outstanding stock of Phillips Casing and Tubing, Inc. (Phillips) for total consideration of $30.7 million. Both of these acquisitions resulted in increased OCTG inventory and revenues from the date of acquisition. Our tubular services segment shipped 182,600 tons of OCTG in the first half of 2005 (100,600 tons in the second quarter of 2005) compared to 151,900 tons in the first half of 2004 (84,600 tons in the second quarter of 2004). Our tubular services segment benefited in the past six months from a 16.2% year over year increase in average U.S. land drilling activity, the acquisition of the Hunting and Phillips OCTG distribution businesses and a significant increase in OCTG prices. Tubular services margins expanded since the first half of 2004 and have reached historically high levels given the significant increase in OCTG prices coupled with strong demand.

     Our offshore products segment reported a much improved first half of 2005 compared to the first half of 2004 as a result of increased activity and greater fixed cost absorption. Our offshore products backlog totaled $113.5 million at June 30, 2005, $97.5 million at December 31, 2004 and $98.7 at June 30, 2004. We believe that the offshore construction and development business is characterized by lengthy projects and a long “lead-time” order cycle. While change in backlog levels from one quarter to the next does not necessarily evidence a long-term trend, we believe activity levels in our offshore products segment will increase in future quarters, given the growth in our backlog, when compared to year end 2004 levels.

     The Company’s income tax provision for the first half of 2005 totaled $29.3 million, or 36.9% of pretax income. Our effective tax rate increased in the first half of 2005 compared to the first half of 2004. Our first half of 2004 results reflected an effective tax rate of 25.2% due to greater NOL benefits recognized in the first quarter of 2004 when a $5.4 million income tax benefit was recognized upon a partial reversal of valuation allowances applied against net operating loss carryforwards. In the second quarter of 2005, our income tax provision totaled $14.5 million, 36.9% of pretax income compared to $8.0 million, or 39.8% of pretax income in the second quarter of 2004.

     Management believes that fundamental oil and gas supply and demand factors will continue to support a high level of drilling activity in North America over time which should continue to positively impact the Company, particularly its tubular services and well site service segments. We also believe that oil and gas producers have increased their view of longer term oil and gas prices based on current supply and demand fundamentals, even though such long term price expectations are still at levels below current prices. As a result, our customers could increase their spending on deepwater offshore exploration and development which should benefit our offshore products segment. However, there can be no assurance that these expectations will be realized.

     Revenues. Total revenues increased $136.3 million, or 61.3%, to $358.5 million during the current quarter compared to revenues of $222.2 million during the quarter ended June 30, 2004. Offshore products revenues increased $14.9 million, or 30.4%, due to higher activity levels supporting offshore production facility construction. Tubular services revenues and tons shipped increased $67.4 million, or 67.1%, and 16,000 tons, or 18.9%, respectively, in the three months ended June 30, 2005 compared to the three months ended June 30, 2004 due to increased industry demand, higher OCTG prices, contributions from the Hunting acquisition completed in May 2004 and the Phillips acquisition that closed in June 2005. Our average OCTG selling prices increased 40.5% from the second quarter of 2004 to the second quarter of 2005. Well site services revenues increased $54 million, or 74.2%, to $126.8 million during the current quarter compared to $72.8 million during the quarter ended June 30, 2004. Our drilling revenues increased $8.6 million, or 77.5%, because of contributions from the Elenburg acquisition which added 7 rigs in February 2005, higher dayrates earned and additional rigs added to the fleet. The Elenburg acquisition accounted for $5.6 million of the $8.6 million increase in revenues generated from the Company’s

drilling operations. In our workover operations, activity in the U.S. Gulf, Venezuela, and West Africa was higher in 2005 than 2004 resulting in a $1.0 million increase in revenues. The rental tools business generated revenues in the second quarter of 2005 of $31.2 million, which were $14.1 million, or 82.5%, higher than the second quarter of 2004 due to capital expenditures made since last year, the acquisition of Stinger, improving U.S. drilling activity and modest price increases. The Stinger acquisition was responsible for $11.0 million of the $14.1 million increase in revenues generated from the Company’s rental tools business line. Accommodations revenues in the second quarter of 2005 were $30.3 million, or 87.3%, higher than accommodations revenues reported in the second quarter of 2004 primarily because of increased activity in support of the oil sands region of Canada.

     Gross Margin. Our gross margins, which we calculate before a deduction for depreciation expense, increased $27.6 million, or 59.7%, from $46.2 million in the quarter ended June 30, 2004 to $73.8 million in the quarter ended June 30, 2005. Our overall gross margin as a percent of revenues was 20.6% in the second quarter of 2005 compared to 20.8% in the second quarter of 2004. Overall margins as a percentage of revenue declined slightly primarily because a greater percentage of accommodations revenues was generated by manufacturing activities which generally earn a lower margin than accommodations rental and service activities, in the second quarter of 2005.

     Total gross margins at offshore products were $14.2 million in the second quarter of 2005 compared to $10.0 million in the same period of the prior year representing an increase of 42.0%. Offshore products margin percentage improved from 20.4% in the second quarter of 2004 to 22.2% in the second quarter of this year as higher activity resulted in greater overhead absorption, which was partially offset by the negative impact of greater job loss reserves recorded in the current year.

     Tubular services gross margins increased by $8.2 million, or 62.6%, in the three months ended June 30, 2005 compared to the three months ended June 30, 2004 as a result of price increases and increased oil and gas drilling activity which strengthened demand for our tubular products and services. Our tubular services segment gross margin as a percent of revenues was relatively flat at 12.7% in the second quarter of 2005 when compared to 13.0% in the second quarter of 2004.

     Well site services gross margins increased by $15.2 million, or 65.8%, during the quarter ended June 30, 2005 compared to the quarter ended June 30, 2004. Drilling gross margins in the second quarter of 2005 totaled $6.4 million compared to $3.3 million in the second quarter of 2004, an increase of $3.1 million, or 93.9%. Of the $3.1 million increase in drilling gross margins, $1.9 million was generated from the Elenburg acquisition. The gross margin percentage improved to 32.5% of revenues in the second quarter of 2005 from 28.8% of revenues in the second quarter of 2004 due primarily to higher dayrates. Rental tools gross margins totaled $15.7 million in the second quarter of 2005 compared to $7.4 million in the second quarter of 2004, an increase of $8.3 million, or 112.2%. Rental tools gross margin percentage increased from 43.3% for the second quarter of 2004 to 50.3% in the second quarter of 2005. The improvement in gross margins resulted from higher utilization of tools, modestly higher rental rates and the positive impact of the Stinger acquisition. Of the $8.3 million increase in rental tools gross margins, $5.8 million was generated by Stinger in May and June 2005. Workover gross margins improved to $3.8 million in the three months ended June 30, 2005 compared to $2.9 million in the three months ended June 30, 2004, an improvement of $0.9 million, or 31.0%. The workover gross margin percentage increased to 34.9% of revenues in the second quarter of 2005 compared to 29.3% in the second quarter of 2004 due to a greater mix of activity involving lower cost workover activity and slightly higher dayrates. Accommodations gross margins in the second quarter of 2005 totaled $12.4 million compared to $9.5 million in the second quarter of 2004, an increase of $2.9 million, or 30.5%. The gross margin percentage declined to 19.1% in the second quarter of 2005 compared to a 27.4% gross margin percentage for the second quarter of 2004 due to the higher relative mix of lower margin manufacturing revenues.

     Selling, General and Administrative Expenses. Selling, general and administrative expenses (SG&A) increased $4.8 million, or 30.2% in the second quarter of 2005 compared to the same period in 2004. During the three months ended June 30, 2005, SG&A totaled $20.7 million, or 5.8% of revenues, compared to SG&A of $15.9 million, or 7.1% of revenues, for the three months ended June 30, 2004. Increased SG&A expense associated with acquisitions completed since the second quarter of 2004, higher ad valorem taxes for OCTG inventory, increased incentive compensation accruals, and higher professional fees associated with Sarbanes-Oxley compliance were the primary factors causing increased SG&A in 2005 compared to 2004.

     Depreciation and Amortization. Depreciation and amortization expense increased $2.5 million, or 28.7%, in the second quarter 2005 compared to the second quarter 2004 due primarily to acquisitions of businesses and capital expenditures made in the past year.

     Operating Income. Our operating income represents revenues less (i) cost of sales, (ii) selling, general and administrative expenses, (iii) depreciation and amortization expense, and (iv) other operating (income) expense. Our operating income increased $20.4 million, or 94.4%, to $42.0 million for the three months ended June 30, 2005 from $21.6 million for the three months ended June 30, 2004. Offshore products operating income increased $2.7 million, tubular services operating income increased $7.5 million and well site services operating income increased $11.0 million. These increases were partially offset by higher corporate costs of $0.8 million.

     Interest Expense. Interest expense increased $1.3 million, or 72.6%, for the quarter ended June 30, 2005 compared to the quarter ended June 30, 2004. Interest expense increased due to higher debt levels resulting from acquisitions completed since the second quarter of 2004 and capital expenditures, combined with higher interest rates.

     Income Tax Expense. Income tax expense totaled $14.5 million, or 36.9% of pretax income, during the quarter ended June 30, 2005 compared to $8.0 million, or 39.8% of pretax income, during the quarter ended June 30, 2004. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Tax Matters” discussion below.

     Revenues. Total revenues increased $264.0 million, or 61.9%, to $690.4 million during the six months ended June 30, 2005 compared to revenues of $426.4 million during the six months ended June 30, 2004. Offshore products revenues increased $39.6 million, or 43.6%, due to higher activity levels supporting offshore production facility construction. Tubular services revenues and tons shipped increased $139.0 million, or 83.4%, and 30,700 tons, or 20.2%, respectively, in the six months ended June 30, 2005 compared to the six months ended June 30, 2004 due to increased industry demand, higher OCTG prices, the Hunting acquisition completed in May 2004 and the Phillips acquisition that closed in June 2005. Our average OCTG selling prices increased 52.6% from the first half of 2004 to the first half of 2005. Well Site services revenues increased $85.4 million, or 50.5%, to $254.4 million during the first half of 2005 compared to $169.0 million during the first half of 2004. Our drilling revenues increased $14.8 million, or 67.9%, because of contributions from the Elenburg acquisition, which added 7 rigs in February 2005, higher dayrates earned and additional rigs added to the fleet. The Elenburg acquisition was responsible for $5.6 million of the $14.8 million increase in revenues generated from the Company’s drilling operations. Our hydraulic workover revenues increased by $1.8 million, or 10.3%, in the first half of 2005 compared to the same period in 2004 because of higher activity in the U.S. Gulf and Venezuela, which was partially offset by lower revenues in the Middle East. Rental tools generated revenues in the six months ended June 30, 2005 of $50.3 million, which were $17.8 million, or 54.8%, higher than the six months ended June 30, 2004 due to the capital expenditures made since last year, the acquisition of Stinger, improving U.S. drilling activity and modest price increases. The Stinger acquisition accounted for $11.0 million of the $17.8 million revenue increase generated by the Company’s rental tools business line. Accommodations revenues in the six months ended June 30, 2005 were $148.2 million, an increase of $51.0 million, or 52.5%, over the accommodations revenues reported in the six months ended June 30, 2004 primarily because of increased activity in support of the oil sands region of Canada.

     Gross Margin. Our gross margins, which we calculate before a deduction for depreciation expense, increased $55.9 million, or 62.7%, from $89.1 million in the six months ended June 30, 2004 to $145.0 million in the six months ended June 30, 2005. Our overall gross margin as a percent of revenues was 21.0% in the first half of 2005 compared to 20.9% in the first half of 2004. Gross margin percentages increased in all businesses except accommodations where a greater percentage of revenues was generated by manufacturing activities which generally earn a lower margin than accommodations rental and service activities.

     Total gross margins at offshore products were $28.3 million in the first six months of 2005 compared to $17.1 million in the same period of the prior year, representing an increase of 65.5%. Offshore products margin

percentage improved from 18.8% in the first six months of 2004 to 21.7% in the first six months of 2005 due to higher activity and greater overhead absorption, which was partially offset by the negative impact of greater job loss reserves recorded in the current year.

     Tubular services gross margins increased $20.3 million, or 106.8% in the six months ended June 30, 2005 compared to the six months ended June 30, 2004 as a result of price increases and increased oil and gas drilling activity which strengthened demand for our tubular products and services. Our tubular services segment gross margin as a percent of revenues increased from 11.4% in the first six months of 2004 to 12.9% in the first six months of 2005 because of a greater impact of rising prices for OCTG in the 2005 period.

     Well Site services gross margins increased by $24.4 million, or 46.0%, during the first six months of 2005 compared to the first six months of 2004. Drilling gross margins in the six months ended June 30, 2005 totaled $12.2 million compared to $6.5 million in the six months ended June 30, 2004, an increase of $5.7 million, or 87.7%. Of the $5.7 million increase in drilling gross margins, $3.1 million was generated by the Elenburg acquisition. The gross margin percentage improved to 33.3% of revenues in the first half of 2005 from 29.8% of revenues in the first half of 2004 due primarily to higher dayrates. Workover gross margins improved by $0.9 million, or 20%, in the first half of 2005 compared to the same period of the prior year because of higher activity in the U.S. Gulf and Venezuela. The workover gross margin percentage increased to 28.0% of revenues in the first half of 2005 compared to 25.7% in the first half of 2004 due primarily to higher utilization. Rental tools gross margins totaled $24.4 million in the six months ended June 30, 2005 compared to $14.2 million in the six months ended June 30, 2004, an increase of $10.2 million, or 71.8%. Rental tools gross margin percentage increased from 43.7% for the first half of 2004 to 48.5% in the first half of 2005. The improvement resulted from higher utilization of tools, modestly higher rental rates and the positive impact of the Stinger acquisition. Of the $10.2 million increase in rental tools gross margins, $5.8 million was generated by Stinger in May and June 2005. Accommodations gross margins in the six months ended June 30, 2005 totaled $35.4 million compared to $27.8 million in the six months ended June 30, 2004, an increase of $7.6 million, or 27.3%. The gross margin percentage declined to 23.9% in the first half of 2005 compared to the 28.6% gross margin percentage for the first half of 2004 due to a higher relative mix of lower margin manufacturing revenues.

     Selling, General and Administrative Expenses. Selling, general and administrative expenses (SG&A) increased $9.2 million, or 29.9%, in the first six months of 2005 compared to the same period in 2004. During the six months ended June 30, 2005, SG&A totaled $39.7 million, or 5.8% of revenues, compared to SG&A of $30.6 million, or 7.2% of revenues, for the six months ended June 30, 2004. Increased SG&A expense associated with acquisitions completed since the first half of 2004, higher ad valorem taxes for OCTG inventory, increased incentive compensation accruals, and higher professional fees associated with Sarbanes-Oxley compliance were the primary factors causing the increased SG&A in 2005 compared to 2004.

     Depreciation and Amortization. Depreciation and amortization expense increased $4.1 million, or 23.8%, in the first six months of 2005 compared to the first six months of 2004 due primarily to acquisitions of businesses and capital expenditures made in the past year.

     Operating Income. Our operating income represents revenues less (i) cost of sales, (ii) selling, general and administrative expenses, (iii) depreciation and amortization expense, and (iv) other operating (income) expense. Our operating income increased $43.5 million, or 106.9%, to $84.2 million for the six months ended June 30, 2005 from $40.7 million for the six months ended June 30, 2004. Offshore products operating income increased $8.8 million, tubular services operating income increased $19.0 million and well site services operating income increased $18.0 million. These increases were partially offset by higher corporate costs of $2.3 million.

     Interest Expense. Interest expense increased $2.0 million, or 57.3%, for the six months ended June 30, 2005 compared to the six months ended June 30, 2004. Interest expense increased due to higher debt levels resulting from acquisitions completed since June 30, 2004 and capital expenditures, combined with higher interest rates.

     Income Tax Expense. Income tax expense totaled $29.3 million, or 36.9% of pretax income, during the six months ended June 30, 2005 compared to $9.6 million, or 25.2% of pretax income, during the six months ended June 30, 2004. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Tax Matters” discussion below.

     Our primary liquidity needs are to fund capital expenditures, such as expanding and upgrading our manufacturing facilities and equipment, increasing and replacing our drilling rig, rental tool and workover assets, and our accommodation units, funding new product development and funding general working capital needs. In addition, capital is needed to fund strategic business acquisitions. Our primary sources of funds have been cash flow from operations, proceeds from borrowings under our bank facilities and more recently, proceeds from our convertible bond offering.

     Cash totaling $42.3 million was provided by operations during the six months ended June 30, 2005 compared to cash totaling $58.4 million provided by operations in the six months ended June 30, 2004. During the first half of 2005, $34.0 million was used to fund working capital. Significantly increased working capital was invested in tubular services inventory due to increased volumes and prices paid.

     Cash was used in investing activities during the six months ended June 30, 2005 and 2004 in the amount of $179.2 million and $98.8 million, respectively. Capital expenditures totaled $33.9 million and $20.8 million during the six months ended June 30, 2005 and 2004, respectively. Capital expenditures in both years consisted principally of purchases of assets for our well site services segment. In addition, we completed various acquisitions totaling $145.8 million net of cash acquired, during the first six months of 2005.

     On February 1, 2005, the Company completed the acquisition of Elenburg Exploration Company, Inc. (Elenburg), a Wyoming based land drilling company for cash consideration of $21.3 million, including transaction costs, plus a note payable to the former owners of $0.8 million. Elenburg owns and operates 7 rigs which provide shallow land drilling services in Montana, Wyoming, Colorado, and Utah.

     Effective May 1, 2005 the Company acquired Stinger Wellhead Protection, Inc., certain affiliated companies and related intellectual property, (collectively, “Stinger”) for cash consideration of $77.9 million, net of cash acquired and including transaction costs, plus a note payable to the former owners of $5.0 million. Stinger provides wellhead isolation equipment and services through its 23 locations in the United States and Canada. Stinger’s patented equipment is utilized during pressure pumping operations and isolates the customers’ blow-out preventers or wellheads from the pressure and abrasion experienced during the fracturing process of an oil or gas well. In June 2005, the Company completed the acquisition of Stinger’s international operations for additional cash consideration of $6.1 million, net of cash acquired and including transaction costs. The Stinger international operations are conducted primarily in Central and South America. The Stinger acquisition expanded the Company’s rental tool and services capabilities, especially in the pressure pumping market.

     On June 2, 2005, the Company purchased Phillips Casing and Tubing, L.P. (Phillips) for cash consideration of $30.7 million, net of cash acquired and including transaction costs. Phillips distributes oil country tubular goods (OCTG), primarily carbon ERW (electronic resistance welded) pipe, from its facilities in Midland and Godley, Texas.

     On June 6, 2005, the Company acquired Noble Structures, Inc. into its well site services segment for cash consideration of $7.9 million, including a note payable of $0.8 million. The acquisition expanded the Company’s accommodation manufacturing capabilities in Canada in order to meet increased demand for remote site facilities, principally in the oil sands region.

     The cash consideration paid for all of the Company’s acquisitions in the period was initially funded utilizing its existing bank credit facility and a $25 million bridge loan (See Note 6). Accounting for the acquisitions made in the period has not been finalized and is subject to adjustments during the purchase price allocation period, which is not expected to exceed a period of one year from the respective acquisition dates.

     We currently expect to spend a total of approximately $84.3 million for capital expenditures during 2005 for maintenance and upgrade of our equipment and facilities and also to expand our product and service offerings. We expect to fund these capital expenditures with internally generated funds and proceeds from borrowings under our revolving credit facilities.

     Net cash of $143.8 million was provided by financing activities during the six months ended June 30, 2005, primarily as a result of revolving credit borrowings and the issuance of $125 million aggregate principal amount of 2 3/8% contingent convertible senior notes due in 2025 (2 3/8% notes) in the second quarter of 2005. Net proceeds from the 2 3/8% notes were utilized to repurchase $30 million of the Company’s common stock, which was classified as treasury stock at June 30, 2005, to repay an outstanding bridge loan of $25 million and to repay indebtedness of $66 million under our revolving credit facility. During the first quarter of 2005, the Company’s Board of Directors authorized the repurchase of up to $50 million of the Company’s common stock, par value $.01 per share, over a two year period. Through June 30, 2005, a total of $30 million of the Company’s stock, acquired in connection with the issuance of the 2 3/8% notes, has been repurchased under this program.

     Our primary bank credit facility (the “Credit Facility”), which matures in January 2010, provides for $325 million of revolving credit. The credit agreement, which governs our Credit Facility (the “Credit Agreement”), contains customary financial covenants and restrictions, including restrictions on our ability to declare and pay dividends. Borrowings under the Credit Agreement are secured by a pledge of substantially all of our assets and the assets of our subsidiaries. Our obligations under the Credit Agreement are guaranteed by our significant subsidiaries. Borrowings under the Credit Agreement accrue interest at a rate equal to either LIBOR or another benchmark interest rate (at our election) plus an applicable margin based on our leverage ratio (as defined in the Credit Agreement). We must pay a quarterly commitment fee, based on the Company’s leverage ratio, on the unused commitments under the Credit Agreement. During the first half of 2005, our applicable margin over LIBOR ranged from 1% to 2% and it was 1% as of June 30, 2005.

     As of June 30, 2005, we had $221.5 million outstanding under the Credit Facility and an additional $10.9 million of outstanding letters of credit, leaving $92.6 million available to be drawn under the facility. In addition, we have other floating rate bank credit facilities in the U.S. and the U.K. that provide for an aggregate borrowing capacity of $8.6 million. We had no borrowings outstanding under these other facilities as of June 30, 2005. Our total debt represented 39.1% of our total capitalization at June 30, 2005.

     Subsequent to June 30, 2005, the Company sold an additional $50 million of the 2 3/8% contingent convertible senior notes subject to the underwriter’s option, which the company had granted at the time of the initial sale of the notes. Net proceeds from the additional sale of notes, totaling $48.5 million, were used to repay borrowings under its senior secured credit facility.

     We believe that cash from operations and available borrowings under our credit facilities will be sufficient to meet our liquidity needs in the coming twelve months. If our plans or assumptions change or are inaccurate, or if we make further acquisitions, we may need to raise additional capital. However, there is no assurance that we will be able to raise additional funds or be able to raise such funds on favorable terms.

     Our primary deferred tax asset, which totaled approximately $12.5 million at December 31, 2004, is related to $35.8 million in available federal net operating loss carryforwards, or NOLs, as of that date. A valuation allowance of approximately $5.1 million was provided against the deferred tax asset associated with our NOLs at December 31, 2004. The NOLs will expire in varying amounts during the years 2010 through 2020 if they are not first used to offset taxable income generated by the Company. The Company’s ability to utilize a significant portion of the NOLs is currently limited under Section 382 of the Internal Revenue Code due to a change of control that occurred during 1995. A successive change in control was triggered in 2003 pursuant to Section 382; however it did not significantly change the Company’s NOL utilization expectations.

     The Company’s income tax provision for the three months ended June 30, 2005 totaled $14.5 million, or 36.9% of pretax income, compared to $8.0 million, or 39.8% of pretax income, for the three months ended June 30, 2004.

     The Company’s income tax provision for the six months ended June 30, 2005 totaled $29.3 million, or 36.9%, of pretax income compared to $9.6 million, or 25.2%, of pretax income for the six months ended June 30, 2004. Our effective tax rate was lower in the first half of 2004 as a result of the recognition of a $5.4 million income tax benefit related to the partial reversal of the valuation allowance applied against NOLs which were recorded as of the prior year end.

     We currently estimate that our effective tax rate for the full year 2005 will approximate 35% to 38%. Our actual effective tax rate could differ materially from this estimate, which is subject to a number of uncertainties, including future taxable income projections, the amount of income attributable to domestic versus foreign sources, the amount of capital expenditures and any changes in applicable tax laws and regulations. Based upon the loss limitation provisions of Section 382, we should be able to utilize approximately $8 million of our NOLs to offset taxable income generated by the Company during the tax year ended December 31, 2005.

     In the fourth quarter of 2004, the FASB issued Statement No. 123 (revised 2004), or SFAS No. 123R, “Share-Based Payment,” which replaces Statement No. 123 “Accounting for Stock-Based Compensation,” and supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS No. 123R eliminates the alternative to use APB Opinion 25’s intrinsic value method of accounting that was provided in Statement No. 123 as originally issued. After a phase-in period for Statement No. 123R, pro forma disclosure will no longer be allowed. In the first quarter of 2005 the Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin No. 107 which provided further clarification on the implementation of SFAS No. 123R.

     Alternative phase-in methods are allowed under Statement No. 123R, which was to be effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. In April 2005, the Securities and Exchange Commission (“SEC”) adopted a rule that defers the required effective date of SFAS No. 123R. The SEC rule provides that SFAS No. 123R is now effective for registrants as of the beginning of the first fiscal year beginning after June 15, 2005. We are currently in the process of evaluating the impact of SFAS No. 123R on our consolidated condensed financial statements. We will adopt SFAS No. 123R on January 1, 2006.

     Interest Rate Risk. We have long-term debt and revolving lines of credit that are subject to the risk of loss associated with movements in interest rates. As of June 30, 2005, we had floating rate obligations totaling approximately $221.5 million for amounts borrowed under our revolving credit facilities. These floating-rate obligations expose us to the risk of increased interest expense in the event of increases in short-term interest rates. If the floating interest rate were to increase by 1% from June 30, 2005 levels, our consolidated interest expense would increase by a total of approximately $2.2 million annually.

     Foreign Currency Exchange Rate Risk. Our operations are conducted in various countries around the world in a number of different currencies. As such, our earnings are subject to movements in foreign currency exchange rates when transactions are denominated in currencies other than the U.S. dollar, which is our functional currency or the functional currency of our subsidiaries, which is not necessarily the U.S. dollar. In order to mitigate the effects of exchange rate risks, we generally pay a portion of our expenses in local currencies and a substantial portion of our contracts provide for collections from customers in U.S. dollars. We have hedged U.S. dollar balances and cash flows totaling $8.0 million in our U.K. subsidiary in the second quarter of 2005 through the first quarter of 2006. Results of operations have not been materially affected by foreign currency hedging activity.

     As of the end of the period covered by this Quarterly Report on Form 10-Q, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934). Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2005 in ensuring that material information was accumulated and communicated to management, and made

known to our Chief Executive Officer and Chief Financial Officer, on a timely basis to allow disclosure as required in this Quarterly Report on Form 10-Q. During the three months ended June 30, 2005, there were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934) or in other factors which have materially affected our internal control over financial reporting, or are reasonably likely to materially affect our internal control over financial reporting.

     We are a party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning our commercial operations, products, employees and other matters, including occasional claims by individuals alleging exposure to hazardous materials as a result of our products or operations. Some of these claims relate to matters occurring prior to our acquisition of businesses, and some relate to businesses we have sold. In certain cases, we are entitled to indemnification from the sellers of businesses and in other cases, we have indemnified the buyers that purchased businesses from us. Although we can give no assurance about the outcome of pending legal and administrative proceedings and the effect such outcomes may have on us, we believe that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by indemnity or insurance, will not have a material adverse effect on our consolidated financial position, results of operations or liquidity.

     On February 18, 2005, the Company announced that it had conducted an internal investigation prompted by the discovery of over billings totaling approximately $400,000 by one of its subsidiaries to a government owned oil company in South America. The over billings were detected by the Company during routine financial review procedures, and appropriate financial statement adjustments were included in its previously reported fourth quarter 2004 results. The Company and independent counsel retained by the Company’s audit committee conducted separate investigations consisting of interviews and an examination of the facts and circumstances in this matter. The Company has voluntarily reported the results of its investigation to the Securities and Exchange Commission (the “SEC”) and will fully cooperate with any additional requests for information received from the SEC.

     The Company’s Annual Meeting of Stockholders was held on May 18, 2005 (1) to elect two Class I members of the Board of Directors to serve for three-year terms; (2) to ratify the appointment of Ernst & Young LLP as independent accountants for the year ended December 31, 2005, and (3) to approve the Oil States International, Inc. Equity Participation Plan, as amended and restated effective as of February 16, 2005.

     The two Class I directors who were so elected were L.E. Simmons and Douglas E. Swanson. The number of affirmative votes and the number of votes withheld for the directors so elected were:

     Following the annual meeting Martin Lambert, S. James Nelson, Mark Papa, Stephen Wells, Gary L. Rosenthal and Andrew L. Waite continued in their terms as directors.

     The number of affirmative votes, the number of negative votes and the number of abstentions with respect to the ratification of the appointment of Ernst & Young LLP were as follows:

     The number of affirmative votes, the number of negative votes and the number of abstentions with respect to the approval of the Oil States International, Inc. Equity Participation Plan, as amended and restated effective as of February 16, 2005 were as follows:

     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.