Edgar Filing: TODCO

e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)


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

For the quarterly period ended June 30, 2005


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

For the transition period from to

Commission File Number 1-31983

TODCO

(Exact name of registrant as specified in its charter)


Delaware (State or other jurisdiction of incorporation or organization)		76-0544217 (I.R.S. Employer Identification No.)


2000 W. Sam Houston Parkway South, Suite 800 Houston, Texas 77042-3615 (Address of registrant’s principal executive offices)		(713) 278-6000 (Registrant’s telephone number, including area code)

Indicate by check mark whether the Registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the Registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes o No þ

As of July 31, 2005, 61,021,760 shares of Class A common stock were outstanding and no shares of Class B common stock were outstanding.

TABLE OF CONTENTS


	Page
	Number
PART I – FINANCIAL INFORMATION

Item 1. Condensed Consolidated Balance Sheets at June 30, 2005 and December 31, 2004		2
Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2005 and 2004		3
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2005 and 2004		4
Notes to Condensed Consolidated Financial Statements		5

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		18

Item 3. Quantitative and Qualitative Disclosures About Market Risk		32

Item 4. Controls and Procedures		32

PART II – OTHER INFORMATION

Item 1. Legal Proceedings		33

Item 4. Submission of Matters to a Vote of Security Holders		33

Item 6. Exhibits		34
Rule 13a-14a/15d-14a Certification of CEO
Rule 13a-14a/15d-14a Certification of CFO
Section 1350 Certification of CEO and CFO

PART I

Item 1. Financial Statements (Unaudited)

TODCO AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


	June 30,			December 31,
	2005			2004
	(Unaudited)
	(In millions,
	except share data)
ASSETS
Cash and cash equivalents	$	106.6		$	65.1
Accounts receivable
Trade		94.1			67.2
Related party		10.1			11.5
Other		5.6			3.8
Supplies		4.0			4.3
Deferred income taxes		3.5			3.5
Other current assets		2.4			2.5

Total current assets		226.3			157.9


Property and equipment		918.6			920.8
Less accumulated depreciation		395.8			353.6

Property and equipment, net		522.8			567.2


Other assets		31.6			36.3

Total assets	$	780.7		$	761.4

LIABILITIES AND STOCKHOLDERS’ EQUITY
Trade accounts payable	$	26.4		$	20.6
Accrued income taxes		11.3			10.6
Accrued income taxes—related party		14.5			8.4
Debt due within one year		2.1			8.2
Debt due within one year—related party		3.0			3.0
Interest payable—related party		0.1			0.2
Other current liabilities		46.0			45.5
Current liabilities related to discontinued operations		0.2			0.2

Total current liabilities		103.6			96.7


Long-term debt		17.7			17.2
Deferred income taxes		155.4			163.6
Other long-term liabilities		4.4			3.3

Total long-term liabilities		177.5			184.1


Commitments and contingencies
Preferred stock, $0.01 par value, 50,000,000 shares authorized and no shares issued and outstanding		—			—
Common stock, Class A, $0.01 par value, 500,000,000 shares authorized, 60,752,667 shares and 60,300,746 shares issued and outstanding at June 30, 2005 and December 31, 2004, respectively		0.6			0.6
Common stock, Class B, $0.01 par value, 260,000,000 shares authorized and no shares issued and outstanding		—			—
Additional paid-in capital		6,511.5			6,510.0
Retained deficit		(6,008.4	)		(6,027.5	)
Unearned compensation		(4.1	)		(2.5	)

Total stockholders’ equity		499.6			480.6


Total liabilities and stockholders’ equity	$	780.7		$	761.4

See accompanying notes.

TODCO AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
	(In millions, except per
	share data)
Operating revenues	$	130.5		$	80.8		$	242.4		$	154.6

Costs and expenses
Operating and maintenance		86.5			61.1			155.4			128.0
Depreciation		23.9			24.0			47.9			48.2
General and administrative		9.9			7.2			18.3			19.6
Gain on disposal of assets, net		(5.6	)		(1.9	)		(6.7	)		(4.6	)

		114.7			90.4			214.9			191.2


Operating income (loss)		15.8			(9.6	)		27.5			(36.6	)

Other income (expense), net
Interest income		0.8			—			1.3			0.1
Interest expense		(0.9	)		(1.0	)		(1.9	)		(2.0	)
Interest expense—related party		—			—			(0.1	)		(3.2	)
Loss on retirement of debt		—			—			—			(1.9	)
Other, net		1.0			0.1			1.5			0.6

		0.9			(0.9	)		0.8			(6.4	)


Income (loss) before income taxes		16.7			(10.5	)		28.3			(43.0	)
Income tax expense (benefit)		5.7			(3.1	)		9.2			(13.3	)


Net income (loss)	$	11.0		$	(7.4	)	$	19.1		$	(29.7	)


Net income (loss) per common share:

Basic	$	0.18		$	(0.12	)	$	0.32		$	(0.58	)

Diluted	$	0.18		$	(0.12	)	$	0.31		$	(0.58	)


Weighted average common shares outstanding:
Basic		60.3			60.0			60.2			51.1
Diluted		61.2			60.0			61.0			51.1

See accompanying notes.

TODCO AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended
	June 30,
	2005			2004
	(In millions)
Cash Flows from Operating Activities
Net income (loss)	$	19.1		$	(29.7	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation		47.9			48.2
Deferred income taxes		(17.2	)		(13.6	)
Stock-based compensation expense		4.3			9.4
Net gain on disposal of assets		(6.7	)		(4.6	)
Amortization of debt issue costs		0.4			(0.2	)
Deferred income, net		(5.2	)		(6.7	)
Deferred expenses, net		4.4			3.3
Loss on retirement of debt		—			1.9
Changes in operating assets and liabilities, net of effect of distributions to related parties
Accounts receivable, net		(28.7	)		(2.1	)
Accounts payable and other current liabilities		15.9			(6.2	)
Accounts receivable/payable to related party, net		1.3			5.4
Income taxes receivable/payable, net		6.7			(0.4	)
Other, net		(0.1	)		0.2

Net cash provided by operating activities		42.1			4.9


Cash Flows from Investing Activities
Capital expenditures		(9.1	)		(4.8	)
Proceeds from disposal of assets, net		10.3			9.7

Net cash provided by investing activities		1.2			4.9


Cash Flows from Financing Activities
Payments on short-term debt		(1.1	)		—
Proceeds from short-term debt		2.1			—
Repayments on 6.75% senior notes		(7.7	)		—
Issuance of common stock under long-term incentive plans		3.7			—
Other, net		1.2			(1.9	)

Net cash used in financing activities		(1.8	)		(1.9	)


Net increase in cash and cash equivalents		41.5			7.9

Cash and cash equivalents at beginning of period		65.1			20.0


Cash and cash equivalents at end of period	$	106.6		$	27.9

See accompanying notes.

TODCO AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 1—Nature of Business

TODCO (together with its subsidiaries and predecessors, unless the context requires otherwise, the “Company,” “we” or “our”), is a leading provider of contract oil and gas drilling services, primarily in the United States (“U.S.”) Gulf of Mexico shallow water and inland marine region, an area referred to as the U.S. Gulf Coast. The Company owns and operates 64 drilling rigs, consisting of 24 jackup rigs, 27 barge rigs, three submersible rigs, one platform rig and nine land rigs. The Company contracts its drilling rigs, related equipment and work crews primarily on a dayrate basis to drill oil and natural gas wells.

In January 2001, the Company was acquired by Transocean Inc. (the “Transocean Merger”). In July 2002, Transocean Inc. (“Transocean”) announced plans to divest its Gulf of Mexico shallow and inland water (“Shallow Water”) business through an initial public offering of the Company. During 2003, the Company completed the transfer to Transocean of all assets not related to its Shallow Water business (“Transocean Assets”), including the transfer of all revenue-producing assets. In February 2004, the Company completed its initial public offering and secondary stock offerings were completed in September 2004, December 2004 and May 2005. As of June 30, 2005, Transocean has sold all of its remaining shares of the Company’s common stock. See Note 3.

Note 2—Summary of Significant Accounting Policies and Basis of Consolidation

Basis of Consolidation — These condensed financial statements have been prepared in accordance with the rules of the Securities and Exchange Commission for interim financial statements and do not include all annual disclosures required by accounting principles generally accepted in the United States. These financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the Company’s Form 10-K for the fiscal year ended December 31, 2004. The condensed financial information as of June 30, 2005 and for the three and six months ended June 30, 2005 and 2004 is unaudited, but includes all adjustments that management considers necessary for a fair presentation of the Company’s consolidated results of operations, financial position and cash flows. Results for the three and six months ended June 30, 2005 are not necessarily indicative of results to be expected for the full fiscal year 2005 or any other future periods.

Intercompany transactions and accounts have been eliminated. For investments in joint ventures that either do not meet the criteria of being a variable interest entity or where the Company is not deemed to be the primary beneficiary for accounting purposes, the equity method of accounting is used where the Company’s ownership in the joint venture is between 20 percent and 50 percent and for investments in joint ventures where more than 50 percent is owned and the Company does not have control of the joint venture. The cost method of accounting is used for investments in joint ventures where the Company’s ownership is less than 20 percent and the Company does not have significant influence over the joint venture. For investments in joint ventures that meet the criteria of a variable interest entity and where the Company is deemed to be the primary beneficiary for accounting purposes, such entities are consolidated. See Note 4.

Accounting Estimates — The preparation of consolidated 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, liabilities, revenues, expenses and disclosure of contingent assets and liabilities. The Company evaluates its estimates on an ongoing basis, including those related to bad debts, supplies obsolescence, investments, property and equipment and other long-lived assets, income taxes, personal injury claim liabilities, employment benefits and contingent liabilities. The Company bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from such estimates.

Cash and Cash Equivalents — Cash equivalents are stated at cost plus accrued interest, which approximates fair value. Cash equivalents are highly liquid investments with an original maturity of three months or less. As of June

30, 2005, and December 31, 2004, the Company had $12.0 million and $11.9 million, respectively, of restricted cash to support three performance bonds issued in connection with our contracts with PEMEX in Mexico. This restricted cash is included in other assets on the condensed consolidated balance sheet.

Accounts Receivable and Allowance for Doubtful Accounts — Accounts receivable trade are stated at the historical carrying amount net of write-offs and allowance for doubtful accounts receivable. Interest receivable on delinquent accounts receivable is included in the accounts receivable trade balance and recognized as interest income when collectibility is reasonably assured. Uncollectible accounts receivable trade are written off when a settlement is reached for an amount that is less than the outstanding historical balance. The Company establishes an allowance for doubtful accounts receivable on a case-by-case basis when it believes the collection of specific amounts owed is unlikely to occur. This allowance was $0.3 million and $0.2 million at June 30, 2005, and December 31, 2004, respectively.

Supplies — Supplies are carried at the lower of average cost or market value less an allowance for obsolescence. This allowance was $0.3 million at June 30, 2005 and December 31, 2004.

Stock-Based Compensation — Effective January 1, 2003, the Company adopted the fair value method of accounting for stock-based compensation using the prospective method of transition under Statement of Financial Accounting Standards (“SFAS”) 123, Accounting for Stock-based Compensation (“SFAS 123”). Under the prospective method and in accordance with the provisions of SFAS 148, Accounting for Stock-Based Compensation — Transition and Disclosure (“SFAS 148”), the recognition provisions are applied to all employee awards granted, modified or settled after January 1, 2003.

New Accounting Pronouncements — In December 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 123 (revised 2004) (“SFAS 123(R)”), Share-Based Payment, which is a revision of SFAS 123. SFAS 123(R) supersedes Accounting Principles Board (“APB”) Opinion No. 25 (“APB 25”) and amends SFAS 95, Statement of Cash Flows. Generally, the approach to accounting for share-based payments in SFAS 123(R) is similar to the approach described in SFAS 123. However, SFAS 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values (i.e., pro forma disclosure is no longer an alternative to financial statement recognition). SFAS 123(R) is effective for the Company beginning January 1, 2006. As the Company has already adopted SFAS 123, the Company’s adoption of SFAS 123(R) is not expected to have a material impact on the Company’s consolidated results of operations, financial position or cash flows.

In December 2004, the FASB issued SFAS 153, Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29 (“SFAS 153”). This Statement amends APB Opinion No. 29 to permit the exchange of nonmonetary assets to be recorded on a carry over basis when the nonmonetary assets do not have commercial substance. This is an exception to the basic measurement principal of measuring a nonmonetary asset exchange at fair value. A nonmonetary asset exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. SFAS 153 is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The Company adopted SFAS 153 effective April 1, 2005 and the adoption did not have a material effect on its financial condition or results of operations.

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections (“SFAS 154”). SFAS 154 is a replacement of APB Opinion No. 20, Accounting Changes, and FASB Statement No. 3, Reporting Accounting Changes in Interim Financial Statements. SFAS 154 applies to all voluntary changes in accounting principle and changes the accounting for and reporting of a change in accounting principle. SFAS 154 requires retrospective application to prior periods’ financial statements of a voluntary change in accounting principle unless it is impracticable. Previously, most voluntary changes in accounting principle were required to be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The Company does not anticipate the adoption of SFAS 154 to have a material effect on its financial condition or results of operations.

Reclassifications — Certain reclassifications have been made to prior period amounts to conform to the current period’s presentation.

Note 3—Capital Stock and Related Transactions

Capital Structure — In February 2004, the Company amended its certificate of incorporation to, among other things, create two classes of common stock, Class A and Class B, increase its authorized capital stock and to convert any issued and outstanding shares of the Company’s common stock into Class B common stock. As amended, the Company’s authorized capital stock consists of (i) 500,000,000 shares of Class A common stock, par value $.01 per share, and 260,000,000 shares of Class B common stock, par value $.01 per share, and (ii) 50,000,000 shares of preferred stock, par value $.01 per share.

Capital Stock Transactions and Retirement of Related Party Debt — In February 2004, prior to the Company’s IPO, the Company exchanged $45.8 million in principal amount of its outstanding 7.375% Senior Notes held by Transocean Holdings Inc. (a wholly owned subsidiary of Transocean, “Transocean Holdings”), plus accrued interest thereon, for 359,638 shares of the Company’s Class B common stock (4,367,714 shares of Class B common stock after giving effect to a stock dividend). Immediately following this exchange, the Company exchanged $152.5 million and $289.8 million principal amount of its outstanding 6.75% and 9.5% Senior Notes, respectively, held by Transocean, plus accrued interest thereon, for 3,580,768 shares of the Company’s Class B common stock (43,487,535 shares of Class B common stock after giving effect to a stock dividend). The determination of the number of shares issued in the exchange transactions was based on a method that took into account the IPO price of $12.00 per share. The net effect of these transactions was to decrease notes payable and interest payable to a related party by $528.9 million with an offsetting increase in common stock of $0.5 million and additional paid-in capital of $528.4 million. Additionally, the Company expensed the remaining balance of deferred consent fees associated with these notes and recognized a $1.9 million loss on retirement of debt.

Also in connection with the closing of the IPO, Transocean made additional equity contributions totaling $2.8 million, including $1.0 million in intercompany payable balances owed by the Company to Transocean as of the IPO date.

Initial Public Offering and Related Events — In February 2004, the Company completed the IPO of 13,800,000 shares of its Class A common stock at $12.00 per share. The Company did not receive any proceeds from the initial sale of Class A common stock.

Upon completion of the IPO, the Company entered into various agreements to complete the separation from Transocean, including an employee matters agreement, a master separation agreement and a tax sharing agreement. The master separation agreement provides for, among other things, the assumption by the Company of liabilities relating to the Shallow Water business and the assumption by Transocean of liabilities unrelated to the Shallow Water business, including the indemnification of losses that may occur as a result of certain of the Company’s ongoing legal proceedings. See Note 9.

In February 2004, the Company recorded an equity transaction related to net liabilities related to Transocean’s business of $0.4 million for which legal title had not been transferred to Transocean as of the IPO date in accordance with the business indemnity between the Company and Transocean. The net liabilities related to Transocean’s business totaled $0.2 million at June 30, 2005 and December 31, 2004. The indemnification by Transocean was recorded as a credit to additional paid-in capital with a corresponding offset to a related party receivable from Transocean.

In conjunction with the IPO, the Company entered into a tax sharing agreement with Transocean. See Note 8.

Secondary Stock Offerings — Secondary stock offerings were completed in September 2004, December 2004 and May 2005 in which Transocean sold an additional 17,940,000 shares, 14,950,000 shares and 13,310,000 shares, respectively, of the Company’s Class A common stock. At the closing of the December 2004 secondary stock offering, Transocean converted all of its unsold shares of Class B common stock into an equal number of Class A common stock shares, resulting in there being no shares of Class B common stock outstanding. The Company received no proceeds from the secondary stock offerings. As of June 30, 2005, Transocean has sold all of its remaining shares of the Company’s common stock.

Note 4—Delta Towing

The Company owns a 25 percent equity interest in Delta Towing LLC (“Delta Towing”), a joint venture formed to own and operate the Company’s U.S. marine support vessel business, consisting primarily of shallow water tugs, crewboats and utility barges. The Company previously contributed its support vessel business to the joint venture in return for a 25 percent ownership interest and certain secured notes receivable from Delta Towing with a face value of $144.0 million. The Company valued these notes at $80.0 million and no value was assigned to the ownership interest in Delta Towing. Delta Towing’s property and equipment, with a net book value of $36.8 million at June 30, 2005, are collateral for the Company’s notes receivable. The remaining 75 percent ownership interest is held by Beta Marine LLC (“Beta Marine”), which also loaned Delta Towing $3.0 million. See Note 5.

Under FASB Interpretation No. 46, Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51 (“FIN 46”), Delta Towing is considered a variable interest entity because its equity is not sufficient to absorb the joint venture’s expected future losses. The Company is deemed to be the primary beneficiary of Delta Towing for accounting purposes because it has the largest percentage of investment at risk through the secured notes held by the Company and would thereby absorb the majority of the expected losses of Delta Towing. The Company adopted FIN 46 and, accordingly, consolidated Delta Towing effective December 31, 2003. As of June 30, 2005 and December 31, 2004 all intercompany accounts have been eliminated in consolidation as a result of the adoption of FIN 46, as well as all intercompany transactions during the three and six months ended June 30, 2005 and 2004.

The creditors of Delta Towing have no recourse to the general credit of the Company.

Note 5—Debt and Capital Lease Obligations

Debt and capital lease obligations, net of unamortized discounts, premiums, and fair value adjustments, were comprised of the following (in millions):


	Third Party				Related Party
	June 30,		December 31,		June 30,		December 31,
	2005		2004		2005		2004
6.75% Senior Notes, due April 2005	$	—	$	7.8	$	—	$	—
6.95% Senior Notes, due April 2008		2.2		2.2		—		—
7.375% Senior Notes, due April 2018		3.5		3.5		—		—
9.5% Senior Notes, due December 2008		11.1		11.2		—		—
Other Debt		1.0		—		3.0		3.0
Capital Lease Obligations		2.0		0.7		—		—

Total		19.8		25.4		3.0		3.0
Less debt due within one year		2.1		8.2		3.0		3.0

Total long-term debt	$	17.7	$	17.2	$	—	$	—

Third Party Debt ¾ Revolving Credit Facility ¾ In December 2003, the Company entered into a two-year, $75 million floating-rate secured revolving credit facility that declined to $60 million in December 2004. The facility is secured by most of the Company’s drilling rigs, receivables, and the stock of most of its U.S. subsidiaries and is guaranteed by some of its subsidiaries. Borrowings under the facility bear interest at our option at either (1) the higher of (A) the prime rate and (B) the federal funds rate plus 0.5 percent, plus a margin in either case of 2.50 percent or (2) the Eurodollar rate plus a margin of 3.50 percent. Commitment fees on the unused portion of the facility are 1.5 percent of the average daily balance and are payable quarterly. Borrowings and letters of credit issued under the facility are limited by a borrowing base equal to the lesser of (A) 20 percent of the orderly liquidated value of the drilling rigs securing the facility, as determined from time to time by a third party selected by the agent under the facility, and (B) the sum of 10 percent of the orderly liquidated value of the drilling rigs securing the facility plus 80 percent of the U.S. accounts receivable outstanding less than 90 days, net of any provision for bad debt associated with such U.S. accounts receivable.

Financial covenants include maintenance of certain financial ratios and other ratios, including working capital, liquidity, and debt-to-total capitalization ratios, and a minimum tangible net worth by the Company.

The revolving credit facility provides, among other things, for the issuance of letters of credit that the Company may utilize to guarantee its performance under some drilling contracts, as well as insurance, tax and other obligations in various jurisdictions. The facility also provides for customary fees and expense reimbursements and includes other covenants (including limitations on the incurrence of debt, mergers and other fundamental changes, asset sales and dividends) and events of default (including a change of control) that are customary for similar secured non-investment grade facilities.

During the three and six months ended June 30, 2005, the Company recognized $0.2 million and $0.4 million, respectively, in interest expense related to commitment fees on the unused portion of the facility and recognized $0.3 million and $0.6 million, respectively, for the corresponding periods ending June 30, 2004. During the three and six months ended June 30, 2005 and June 30, 2004, the company amortized $0.3 million, $0.6 million, $0.3 million and $0.6 million, respectively, in deferred financing costs as a component of interest expense. At June 30, 2005 and December 31, 2004, the Company had no borrowings outstanding under this facility.

Senior Notes and Exchange Offer — In 2002, Transocean and the Company completed exchange offers and consent solicitations for the Company’s 6.5%, 6.75%, 6.95%, 7.375%, 9.125%, and 9.5% Senior Notes (the “Exchange Offer”). As a result of the Exchange Offer, the Company’s outstanding 6.5%, 6.75%, 6.95%, 7.375%, 9.125%, and 9.5% Senior Notes were exchanged by Transocean for newly issued Transocean notes having the same principal amount, interest rate, redemption terms and payment and maturity dates (the “Exchanged Notes”). Both the Exchanged Notes and the notes not exchanged remained the obligation of the Company.

In February 2004, prior to the Company’s IPO, the Company exchanged $488.1 million in principal amount of the then outstanding Exchanged Notes, plus accrued interest thereon, for 3,940,406 shares of the Company’s Class B common stock (47,855,249 shares of Class B common stock after giving effect to a stock dividend). In connection with the exchange, the Company recognized $3.1 million in interest expense related to the Exchanged Notes in 2004. There are no Exchanged Notes payables to Transocean outstanding as a result of the above transaction at June 30, 2005 or December 31, 2004.

In connection with the Exchange Offer, the Company had made an aggregate of $8.3 million in consent payments to holders of the notes that were exchanged. The consent payments were amortized as an increase to interest expense over the remaining terms of the Exchanged Notes using the interest method. No amounts were amortized to interest expense in 2004. In connection with the retirement of the Exchanged Notes prior to the completion of the IPO, the Company expensed the remaining balance of these deferred consent fees of approximately $1.9 million in February 2004, which has been reflected as a loss on retirement of debt in the Company’s consolidated statement of operations.

In April 2005, the Company repaid the outstanding balance of $7.7 million related to the 6.75% Senior Notes. As a result, at June 30, 2005, approximately, $2.2 million, $3.5 million, and $10.2 million principal amount of the 6.95%, 7.375%, and 9.5% Senior Notes, respectively, due to third parties were outstanding. The fair value of these notes at June 30, 2005, was approximately $2.2 million, $3.2 million, and $10.9 million, respectively, based on the estimated yield to maturity which takes into account TODCO’s credit worthiness as a separate entity. The Company recognized $0.3 million, $0.7 million, $0.5 million, and $0.9 million in interest expense related to these notes for the three and six months ended June 30, 2005 and 2004, respectively.

Other Debt — Third Party ¾ The Company entered into an unsecured line of credit with a bank in Venezuela in the third quarter of 2004 to provide a maximum of 4.5 billion Venezuela Bolivars ($2.1 million U.S. dollars at the current exchange rate at June 30, 2005) in order to manage local currency liquidity. Each draw on the line of credit is denominated in Venezuela Bolivars and is evidenced by a 30-day promissory note that bears interest at the then market rate as designated by the bank. The promissory notes are pre-payable at any time at the Company’s option. However, if not repaid within 30 days, the promissory notes may be renewed at mutually agreeable terms for an additional 30-day period at the then designated interest rate. There are no commitment fees payable on the unused portion of the line of credit, and the facility is reviewed annually by the bank’s board of directors.

At June 30, 2005, the Company had $1.0 million (2.1 billion Venezuela Bolivars) in borrowings outstanding with respect to the line of credit which bears interest at 17% per annum. This amount is reported as short-term debt in the Company’s condensed consolidated balance sheet at June 30, 2005. The Company recognized $0.1 million in interest expense related to the line of credit for the three and six months ended June 30, 2005.

Other Debt — Related Party ¾ In connection with the acquisition of the U.S. marine support vessel business, Delta Towing entered into a $3.0 million note agreement with Beta Marine dated January 30, 2001. The note bears interest at 8 percent per annum, payable quarterly. The $3.0 million note has been classified as a current obligation in the Company’s condensed consolidated balance sheet at June 30, 2005 and December 31, 2004 as Delta Towing remains in default on this note payable to a related party. The Company has no obligation to fund this debt on behalf of Delta Towing. Interest expense related to the note agreement with Beta Marine was $0 million, $0.1 million, $0 million and $0.1 million for each of the three and six months ending June 30, 2005 and 2004, respectively.

Capital Lease Obligations — From time to time the Company enters into capital lease agreements for certain drilling equipment. In January 2004 and during 2003, the Company entered into three such capital lease agreements and exercised options to buy-out the remaining terms of these lease agreements for $2.3 million in the second quarter of 2004. In August 2004, the Company entered into a two-year capital lease agreement for $0.9 million with a final maturity date in July 2006. The Company exercised its option to buy-out the remaining term of this lease agreement in February 2005 for $0.7 million. The Company entered into additional capital lease agreements for $1.1 million each in January 2005 and June 2005. Future lease payments as of June 30, 2005 under these agreements are $2.2 million, including principal and interest, of which $1.2 million and $1.0 million is payable in the twelve month periods ended June 30, 2006 and 2007, respectively. Interest expense, which is not significant, is included in the future lease payments. Depreciation expense on these assets, which is not significant, is included in depreciation expense.

Note 6—Other Current Liabilities

Other current liabilities are comprised of the following (in millions):


	June 30,		December 31,
	2005		2004
Accrued self-insurance claims	$	22.3	$	21.7
Deferred revenue		3.7		11.4
Accrued payroll and employee benefits		12.3		8.0
Accrued taxes, other than income		7.0		3.2
Other		0.7		1.2

Total other current liabilities	$	46.0	$	45.5

Note 7 — Supplementary Cash Flow Information

Supplementary cash flow information relating to both continuing and discontinued operations is as follows (in millions):


	Six Months Ended
	June 30,
	2005		2004
Non-cash financing activities:
Debt-for-equity exchange (a)	$	—	$	(528.9	)
Equity contributions from parent, net of distributions (b)		7.7		162.0


(a)		Prior to the closing of the Company’s IPO in February 2004, the Company completed a non-cash exchange of $528.9 million in long-term related party notes payable to Transocean and related accrued interest payable for shares of the Company’s Class B common stock. See Notes 3 and 5.

(b)		In connection with the closing of the IPO, the Company completed certain equity transactions related to the Company’s separation from Transocean. In February 2004, the Company recorded business and tax indemnities of the Company by Transocean of $10.7 million as an increase in accounts receivable-related party and an increase in additional paid-in capital and transferred to Transocean $1.0 million of intercompany payable balances as of the IPO date as an increase in additional paid-in capital (see Note 3). Additionally, the Company recorded the book transfer of substantially all pre-IPO income tax benefits to Transocean of $173.7 million as a decrease in deferred income tax assets and a decrease in additional paid-in capital. In the first quarter of 2005, the Company recorded an additional $7.7 million in pre-IPO deferred state tax liabilities that existed at the IPO. This recognition resulted in a $7.7 million reduction in additional paid-in capital, $0.9 million of deferred state tax benefit and a $6.8 million increase in deferred tax liabilities. See Note 8.

Note 8—Income Taxes

Until February 2004, the Company was a member of an affiliated group that included its parent company, Transocean Holdings, and current and deferred taxes were allocated based upon what the Company’s tax provision (benefit) would have been had the Company filed a separate tax return.

Income taxes have been provided based upon the tax laws and rates in the countries in which operations are conducted and income is earned. Deferred tax assets and liabilities are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of the Company’s assets and liabilities using the applicable tax rates in effect. A valuation allowance for deferred tax assets is recorded when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized.

Tax Sharing Agreement—In conjunction with the IPO, the Company entered into a tax sharing agreement with Transocean whereby Transocean will indemnify the Company against substantially all pre-IPO income tax liabilities. However, as part of the tax sharing agreement, the Company must pay Transocean for substantially all pre-IPO income tax benefits utilized or deemed to have been utilized subsequent to the closing of the IPO. Accordingly, the Company recorded an equity transaction in 2004 to eliminate the valuation allowance associated with the pre-IPO tax benefits and reflect the associated liability to Transocean for the pre-IPO tax benefits as a corresponding obligation within the deferred income tax asset accounts. The net effect was a $173.7 million reduction in additional paid-in capital. As of June 30, 2005, the Company had approximately $343 million of estimated pre-IPO income tax benefits subject to this obligation to reimburse Transocean. The additional estimated tax benefits resulted from the closing of the IPO, specified ownership changes, statutory allocations of tax benefits among Transocean’s consolidated group members and other events. The estimated pre-IPO tax benefits and the Company’s corresponding obligation to Transocean may change when Transocean files its 2004 consolidated group tax return.

In addition, Transocean agreed to indemnify TODCO for certain tax liabilities of $10.3 million that existed as of the IPO date. The tax indemnification by Transocean was recorded as a credit to additional paid-in capital with a corresponding offset to a related party receivable from Transocean.

During the three and six months ended June 30, 2005, the Company utilized pre-IPO income tax benefits to offset its current federal income tax obligation for 2005 resulting in a liability to Transocean of $13.0 million and $23.5 million, respectively. Additionally, during the three and six months ended June 30, 2005, the Company utilized pre-IPO state tax benefits resulting in a liability to Transocean of $0.8 million and $1.6 million, respectively. As of June 30, 2005 and December 31, 2004, the Company owed Transocean $14.5 million and $8.4 million, respectively, for pre-IPO federal and state income tax benefits utilized. These liabilities to Transocean are presented within accrued income taxes — related party in the Company’s condensed consolidated balance sheets.

During the first quarter of 2005, the Company recorded an additional $7.7 million in pre-IPO deferred state tax liabilities that existed at the IPO date. The recognition of these pre-IPO deferred state tax liabilities resulted in a $7.7 million reduction in additional paid-in capital, $0.9 million of deferred state tax benefit and a $6.8 million increase in deferred tax liabilities. Without the effect of this deferred state tax benefit, the effective tax rate for the six months ended June 30, 2005, would have been 35.6%.

Additionally, the tax sharing agreement provides that if any person other than Transocean or its subsidiaries becomes the beneficial owner of greater than 50% of the total voting power of the Company’s outstanding voting stock, the Company will be deemed to have utilized all of these pre-IPO tax benefits, and the Company will be required to pay Transocean an amount for the deemed utilization of these tax benefits adjusted by a specified discount factor. This payment is required even if the Company is unable to utilize the pre-IPO tax benefits. If an acquisition of beneficial ownership had occurred on June 30, 2005, the estimated amount that the Company would have been required to pay Transocean would have been approximately $240 million, or 70% of the pre-IPO tax benefits at June 30, 2005.

Under the tax sharing agreement with Transocean, if the utilization of a pre-IPO tax benefit defers or precludes the Company’s utilization of any post-IPO tax benefit, its payment obligation with respect to the pre-IPO tax benefit generally will be deferred until the Company actually utilizes that post-IPO tax benefit. This payment deferral will not apply with respect to, and the Company will have to pay currently for the utilization of pre-IPO tax benefits to the extent of:

	•		up to 20% of any deferred or precluded post-IPO tax benefit arising out of the Company’s payment of foreign income taxes, and

	•		100% of any deferred or precluded post-IPO tax benefit arising out of a carryback from a subsequent year.

Therefore, the Company may not realize the full economic value of tax deductions, credits and other tax benefits that arise post-IPO until it has utilized all of the pre-IPO tax benefits, if ever.

Note 9—Commitments and Contingencies

Litigation — In October 2001, the Company was notified by the U.S. Environmental Protection Agency (“EPA”) that the EPA had identified a subsidiary of the Company as a potentially responsible party in connection with the Palmer Barge Line superfund site located in Port Arthur, Jefferson County, Texas. Based upon the information provided by the EPA and the Company’s review of its internal records to date, the Company disputes its designation as a potentially responsible party and does not expect that the ultimate outcome of this case will have a material adverse effect on its consolidated results of operations, financial position or cash flows. The Company continues to monitor this matter.

In August 2004, certain subsidiaries of the Company were named, along with other defendants, in several complaints that have been filed in the Circuit Courts of the State of Mississippi involving over 700 persons that allege personal injury arising out of asbestos exposure in the course of their employment by some of these defendants between 1965 and 1986. The complaints also name as defendants certain of Transocean’s subsidiaries to whom the Company may owe indemnity and other unaffiliated defendant companies, including companies that allegedly manufactured drilling related products containing asbestos that are the subject of the complaints. The number of unaffiliated defendant companies involved in each complaint ranges from approximately 20 to 70. The complaints allege that the defendant drilling contractors used those asbestos- containing products in offshore drilling operations, land based drilling operations and in drilling structures, drilling rigs, vessels and other equipment and assert claims based on, among other things, negligence and strict liability, and claims authorized under the Jones Act. The plaintiffs seek, among other things, awards of unspecified compensatory and punitive damages. Based on a recent decision of the Mississippi Supreme Court, the Company anticipates that the trial courts may grant motions requiring each plaintiff to name the specific defendant or defendants against whom such plaintiff makes a claim and the time period and location of asbestos exposure so that the cases may be properly severed. In that regard a majority of these cases have been appointed to a special master who has approved a form of questionnaire to be completed by plaintiffs so that claims may be properly served against specific defendants. The form of questionnaire is currently pending approval by the court. The Company has not yet had an opportunity to conduct any discovery nor has it been able to determine the number of plaintiffs, if any, that were employed by it’s subsidiaries or Transocean’s subsidiaries or otherwise have any connection with the Company’s or Transocean’s drilling operations. The Company intends to defend itself vigorously and, based on the limited information available to it at this time, the Company does not expect the ultimate outcome of these lawsuits to have a material adverse effect on its consolidated results of operations, financial position or cash flows.

Due to the limited information available to the Company at this time, the Company has not yet made a determination whether it or Transocean is financially responsible under the terms of the master separation agreement for any losses the Company or Transocean may incur as a result of the legal proceedings described in the foregoing paragraph.

Under the master separation agreement, Transocean has agreed to indemnify the Company for any losses it incurs as a result of the legal proceedings described in the following two paragraphs. See Note 3.

In December 2002, the Company received an assessment for corporate income taxes from SENIAT, the national Venezuelan tax authority, of approximately $20.7 million (based on the current exchange rates at the time of the assessment and inclusive of penalties) relating to calendar years 1998 through 2000. In March 2003 the Company paid approximately $2.6 million of the assessment, plus approximately $0.3 million in interest, and the Company is contesting the remainder of the assessment. After the Company made the partial assessment payment, the Company received a revised assessment in September 2003 of approximately $16.7 million (based on the current exchange rates at the time of the assessment and inclusive of penalties). We do not expect the ultimate resolution of this assessment to have an impact on our consolidated results of operations, financial condition or cash flows.

In 1984, in connection with the financing of the corporate headquarters, at that time, for Reading & Bates Corporation (“R&B”), a predecessor to one of the Company’s subsidiaries, in Tulsa, Oklahoma, the Greater Southwestern Funding Corporation (“Southwestern”) issued and sold, among other instruments, Zero Coupon Series B Bonds due 1999 through 2009 with an aggregate $189 million value at maturity. Paine Webber Incorporated purchased all of the Series B Bonds for resale and in 1985 acted as underwriter in the public offering of most of these bonds. The proceeds from the sale of the bonds were used to finance the acquisition and construction of the headquarters. R&B’s rental obligation was the primary source for repayment of the bonds. In connection with the offering, R&B entered into an indemnification agreement to indemnify Southwestern and Paine Webber from loss caused by any untrue statement or alleged untrue statement of a material fact or the omission or alleged omission of a material fact contained or required to be contained in the prospectus or registration statement relating to that offering. Several years after the offering, R&B defaulted on its lease obligations, which led to a default by Southwestern. Several holders of Series B bonds filed an action in Tulsa, Oklahoma in 1997 against several parties, including Paine Webber, alleging fraud and misrepresentation in connection with the sale of the bonds. In response to a demand from Paine Webber in connection with that lawsuit and a related lawsuit, R&B agreed in 1997 to retain counsel for Paine Webber with respect to only that part of the referenced cases relating to any alleged material misstatement or omission relating to R&B made in certain sections of the prospectus or registration Statement. The agreement to retain counsel did not amend any rights and obligations under the indemnification agreement. There has been only limited progress on the substantive allegations in the case. The trial court has denied class certification, and the plaintiffs’ appeal of this denial to a higher court has been denied. The plaintiffs further appealed that decision and that appeal was denied. The Company disputes that there are any matters requiring the Company to indemnify Paine Webber. In any event, the Company does not expect that the ultimate outcome of this matter will have a material adverse effect on its consolidated results of operations, financial condition or cash flows.

The Company and its subsidiaries are involved in a number of other lawsuits, all of which have arisen in the ordinary course of the Company’s business. The Company does not believe that ultimate liability, if any, resulting from any such other pending litigation will have a material adverse effect on its business or consolidated financial position.

The Company cannot predict with certainty the outcome or effect of any of the litigation matters specifically described above or of any such other pending litigation. There can be no assurance that the Company’s belief or expectations as to the outcome or effect of any lawsuit or other litigation matter will prove correct and the eventual outcome of these matters could materially differ from management’s current estimates.

Surety Bonds ¾ As is customary in the contract drilling business, the Company also has various surety bonds totaling $19.0 million in place as of June 30, 2005 that secure customs obligations and certain performance and other obligations. These bonds were issued primarily in connection with the Company’s contracts with Pemex Exploration and Production (“PEMEX”), the Mexican national oil company, and Petroleos de Venezuela (“PDVSA”), the Venezuelan national oil company.

Self-Insurance — The Company is at risk for the deductible portion of its insurance coverage. In the opinion of management, adequate accruals have been made based on known and estimated exposures up to the deductible portion of the Company’s insurance coverages.

Note 10—Earnings Per Share

The following table sets forth the computation of basic and diluted earnings per share for the three and six months ended June 30, 2005 and 2004:


	Three Months Ended June 30,					Six Months Ended June 30,
	2005		2004			2005		2004
	(in millions, except per share amounts)
Numerator:
Net income (loss)	$	11.0	$	(7.4	)	$	19.1	$	(29.7	)

Denominator:
Weighted average shares outstanding:
Basic		60.3		60.0			60.2		51.1
Employee stock options		0.5		—			0.5		—
Restricted stock awards and other		0.4		—			0.3		—
Diluted		61.2		60.0			61.0		51.1

Earnings (loss) per common share:
Basic	$	0.18	$	(0.12	)	$	0.32	$	(0.58	)

Diluted	$	0.18	$	(0.12	)	$	0.31	$	(0.58	)

For the three and six months ended June 30, 2004, there were 1,658,617 stock options and 304,448 restricted stock awards related to the Company’s Class A common stock outstanding which were not included in the computation of diluted earnings per share because the effect of including the incremental shares was anti-dilutive for the period. No adjustments to net income (loss) were made in calculating diluted earnings per share for the three and six months ended June 30, 2005 and 2004.

Note 11—Stock-Based Compensation Plans

TODCO Long-Term Incentive Plan (the “2004 Plan”) — In February 2004, the Company adopted the 2004 Plan, a long-term incentive plan for certain employees and non-employee directors of the Company, in order to provide additional incentives and to increase the personal stake of participants in the continued success of the Company. The 2004 Plan provides for the grant of options to purchase shares of the Company’s Class A common stock, restricted stock, deferred performance units, share appreciation rights, cash awards, supplemental payments to cover tax liabilities associated with the aforementioned types of awards, and performance awards. Most awards under the 2004 Plan vest over a three-year period. A maximum of 3,000,000 shares of the Company’s Class A common stock were reserved for issuance under the 2004 Plan. In May 2005, the stockholders approved the TODCO 2005 Long-Term Incentive Plan and no further awards will be granted under the 2004 Plan.

TODCO 2005 Long-Term Incentive Plan (the “2005 Plan”) — The 2005 Plan was adopted to continue to provide employees, non-employee directors and consultants to the Company with additional incentives and increase their personal stake in the success of the Company. The 2005 Plan provides for the grant of options to purchase shares of the Company’s Class A common stock, restricted stock, deferred performance units, deferred stock units, share appreciation rights, cash awards, supplemental payments to cover tax liabilities associated with the aforementioned types of awards and performance awards. The number of shares reserved under the 2005 Plan and available for incentive awards is 4,000,000 shares of the Company’s Class A common stock. Additionally, any grants or awards under the 2004 Plan that expire or are forfeited, terminated or otherwise cancelled or that are settled in cash in lieu of shares are reserved and available for incentive awards under the 2005 Plan. Any incentive awards other than stock options under the 2005 Plan reduce the shares available for grant by two shares for every one share granted.

Stock options and restricted stock awards outstanding under both plans as of June 30, 2005 were 1,526,929 and 409,642, respectively. The Company granted 168,489 restricted stock awards during the six months ended June 30, 2005, and none during the three months ended June 30, 2005. An additional 167,481 deferred performance units were granted during the six months ended June 30, 2005, and none during the three months period ended June 30, 2005. The Company granted 22,148 deferred stock units during the three and six months ended June 30, 2005. All of the deferred performance units and deferred stock units issued remain outstanding as of June 30, 2005. In

addition, there were 179,500 stock options granted during the six months ended June 30, 2005 and none granted for the three months period ending June 30, 2005. There were 125,911 and 311,188 stock options exercised during the three and six months period ending June 30, 2005, respectively. The Company received $1.5 million and $3.7 million in proceeds from the exercise of the stock options during the three and six months period ended June 30, 2005, respectively.

During the three and six months ended June 30, 2005, the company recognized $2.5 million and $4.3 million, respectively, in compensation expense related to stock options, restricted stock awards, deferred performance units and deferred stock units granted. During the three and six months ended June 30, 2004, the Company recognized $1.5 million and $7.9 million, respectively, in compensation expense related to stock options and restricted stock awards granted.

Transocean Stock Options — Certain of the Company’s employees hold options to acquire Transocean ordinary shares, which were granted prior to the IPO under a Transocean incentive plan. The employees holding these options were treated as terminated for the convenience of Transocean on the IPO date. As a result, the 250,797 options outstanding on February 10, 2004 became fully vested and were modified to remain exercisable over the original contractual life. In connection with the modification of these options, the Company recognized $0.0 million and $1.5 million of additional compensation expense in the three and six months ended June 30, 2004, respectively. No further compensation expense will be recorded in the future related to the Transocean options.

Note 12 — Gain on Disposal of Assets

During the second quarter of 2005, the Company recorded a net gain on disposal of assets of $5.6 million. Included in the gain on disposal of assets was the sale of THE 192, which was sold for $6.8 million and resulted in a gain of $3.7 million. Additionally, the Company sold drill pipe and miscellaneous equipment resulting in a gain of $1.8 million. A marine support vessel sold by Delta Towing resulted in a gain of $0.3 million on proceeds of $0.9 million.

The Company recorded a $1.1 million net gain on disposal of assets in the first quarter of 2005. This gain resulted from the sale of drill pipe and miscellaneous equipment for $1.1 million for a gain of $0.5 million and the sale of three marine support vessels by Delta Towing for $1.5 million. The Company recorded a gain of $0.6 million related to the sale of the marine support vessels.

During the second quarter of 2004, the Company recognized a net gain on disposal of assets of $1.9 million. The sale of drill pipe and miscellaneous equipment for $1.4 million resulted in a gain of $1.1 million. In addition, Delta Towing sold three marine support vessels for $1.8 million and recognized a gain of $0.8 million.

The net gain on disposal of assets of $2.7 million recognized in the first quarter of 2004 resulted from the sale of a Delta Towing marine support vessel which resulted in a gain of $1.0 million on proceeds of $5.0 million. In addition, the Company recognized as gain and received $1.5 million as payment to settle an insurance claim related to THE 185. The Company recognized an additional $0.2 million related to miscellaneous equipment and drill pipe sales.

Note 13 — Segments, Geographical Analysis and Major Customers

The Company’s operating assets consist of jackup and submersible drilling rigs and inland drilling barges located in the U.S. Gulf of Mexico, jackup rigs and a land rig in Trinidad, jackup drilling rigs and a platform rig in Mexico, as well as land drilling units located in Venezuela. The Company provides contract oil and gas drilling services and reports the results of those operations in four business segments which correspond to the principal geographic regions in which the Company operates: U.S. Gulf of Mexico Segment, U.S. Inland Barge Segment, Other International Segment and Delta Towing Segment.

Operating revenues, depreciation, operating income (loss) and identifiable assets by reportable business segment were as follows (in millions):


	U.S. Gulf of			U.S. Inland			Other			Delta
	Mexico			Barge			International			Towing		Corporate
	Segment			Segment			Segment			Segment		& Other(a)			Total
Three Months Ended:
June 30, 2005
Operating revenues	$	58.5		$	34.9		$	24.4		$	12.7	$	—		$	130.5
Depreciation		12.5			5.9			4.3			1.2		—			23.9
Operating income (loss)		17.6			6.1			(3.0	)		4.0		(8.9	)		15.8

June 30, 2004
Operating revenues	$	30.4		$	25.8		$	17.8		$	6.8	$	—		$	80.8
Depreciation		12.2			5.6			4.9			1.3		—			24.0
Operating income (loss)		(3.2	)		—			(1.0	)		0.8		(6.2	)		(9.6	)

Six Months Ended:
June 30, 2005
Operating revenues	$	110.2		$	64.9		$	44.5		$	22.8	$	—		$	242.4
Depreciation		25.2			11.6			8.7			2.4		—			47.9
Operating income (loss)		30.9			8.9			(3.1	)		6.9		(16.1	)		27.5

June 30, 2004
Operating revenues	$	56.6		$	47.9		$	36.5		$	13.6	$	—		$	154.6
Depreciation		24.6			11.2			9.8			2.6		—			48.2
Operating income (loss)		(11.9	)		(4.6	)		(3.2	)		0.9		(17.8	)		(36.6	)


(a)		Represents general and administrative expenses which were not allocated to a reportable segment.

Total assets by segment were as follows (in millions):


	June 30,		December 31,
	2005		2004
U.S. Gulf of Mexico Segment	$	312.9	$	300.9
U.S. Inland Barge Segment		147.2		160.8
Other International Segment		134.2		154.5
Delta Towing Segment		49.5		51.8
Corporate and Other		136.9		93.4

Total assets	$	780.7	$	761.4

The Company provides contract oil and gas drilling services with different types of drilling equipment in several countries, as well as other marine support services in the U.S. coastal and inland water regions through the Company’s interest in Delta Towing. Geographic information about the Company’s operations was as follows (in millions):


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2005		2004		2005		2004
Operating Revenues
United States	$	106.1	$	63.0	$	197.9	$	118.1
Other countries		24.4		17.8		44.5		36.5

Total operating revenues	$	130.5	$	80.8	$	242.4	$	154.6


	June 30,		December 31,
	2005		2004
Long-Lived Assets
United States	$	452.8	$	473.8
Other countries		101.6		129.7

Total long-lived assets	$	554.4	$	603.5

A substantial portion of the Company’s assets are mobile. Asset locations at the end of the period are not necessarily indicative of the geographic distribution of the earnings generated by such assets during the periods.

The Company’s international operations are subject to certain political and other uncertainties, including risks of war and civil disturbances (or other events that disrupt markets), expropriation of equipment, repatriation of income or capital, taxation policies, and the general hazards associated with certain areas in which operations are conducted.

The Company provides drilling rigs, related equipment and work crews primarily on a dayrate basis to customers who are drilling oil and gas wells. The Company provides these services mostly to independent oil and gas companies, but it also services major international and government-controlled oil and gas companies.

Note 14—Subsequent Events

On July 29, 2005, the Company entered into an agreement to sell THE 151, a non-drilling jackup rig that was taken out of drilling service in May 2003. The Company expects this sale to close in late August or early September 2005, subject to customary closing conditions and to result in a gain of approximately $6 million.

On August 2, 2005, the Company’s Board of Directors declared a special cash dividend of $1.00 per share of common stock payable on August 25, 2005 to stockholders of record on August 15, 2005. The Company expects the aggregate dividend to be approximately $61 million. The Company sought and received a waiver from the lenders under its revolving credit facility to pay this special cash dividend.

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

The following discussion should be read in conjunction with our condensed consolidated financial statements and the related notes included in Item 1 of this report. Except for the historical financial information contained herein, the matters discussed below may be considered “forward-looking” statements. Please see “— Cautionary Statement About Forward-Looking Statements” for a discussion of the uncertainties, risks and assumptions associated with these statements.

Overview of Our Business

We are a leading provider of contract oil and natural gas drilling services, primarily in the United States (“U.S.”) Gulf of Mexico shallow water and inland marine region, an area that we refer to as the U.S. Gulf Coast. We provide these services primarily to independent oil and natural gas companies, but we also service major international and government-controlled oil and natural gas companies. Our customers in the U.S. Gulf Coast typically focus on drilling for natural gas.

We provide contract oil and gas drilling and other support services and report the results of those operations in four business segments which, for our contract drilling services, correspond to the principal geographic regions in which we operate:

	•		U.S. Inland Barge Segment — Our barge rig fleet currently operating in this market segment consists of 12 conventional and 15 posted barge rigs. These units operate in marshes, rivers, lakes and shallow bay or coastal waterways that are known as the “transition zone”. This area along the U.S. Gulf Coast, where jackup rigs are unable to operate, is the world’s largest market for this type of equipment.

	•		U.S. Gulf of Mexico Segment — We currently operate 19 jackup and three submersible rigs in the U.S. Gulf of Mexico shallow water market segment which begins at the outer limit of the transition zone and extends to water depths of about 350 feet. Our jackup rigs in this market segment consist of independent leg cantilever type units, mat-supported cantilever type rigs and mat-supported slot type jackup rigs that can operate in water depths up to 250 feet.

	•		Other International Segment — Our other operations are currently conducted in Mexico, Trinidad and Venezuela. In Mexico, we operate two jackup rigs and a platform rig for PEMEX, the Mexican national oil company. We have two jackup rigs and a land rig in Trinidad and eight land rigs in Venezuela. Additionally, we are preparing a jackup rig to operate in offshore Angola. We may pursue selected opportunities in other regions from time to time.

	•		Delta Towing Segment — We have a partial interest in Delta Towing LLC (“Delta Towing”), a joint venture that operates a fleet of U.S. marine support vessels consisting primarily of shallow water tugs, crewboats and utility barges. We are also a substantial creditor of Delta Towing.

Our operating revenues for our drilling segments are based on dayrates received for our drilling services and the number of operating days during the relevant periods. The level of our operating revenues depends on dayrates, which in turn are primarily a function of industry supply and demand for drilling units in the market segments in which we operate. Supply and demand for drilling units in the U.S. Gulf Coast, which is our primary operating region, has historically been volatile. During periods of high demand, our rigs typically achieve higher utilization and dayrates than during periods of low demand.

Our operating and maintenance costs for our drilling segments represent all direct and indirect costs associated with the operation and maintenance of our drilling rigs. The principal elements of these costs are direct and indirect labor and benefits, freight costs, repair and maintenance, insurance, general taxes and licenses, boat and helicopter rentals, communications, tool rentals and services. Labor, repair and maintenance and insurance costs represent the most significant components of our operating and maintenance costs.

We do not expect operating and maintenance expenses to necessarily fluctuate in proportion to changes in operating revenues because we seek to preserve crew continuity and maintain equipment when our rigs are idle. In general, labor costs increase primarily due to higher salary levels, rig staffing requirements and inflation. Equipment maintenance expenses fluctuate depending upon the type of activity the unit is performing and the age and condition of the equipment.

Industry Background, Trends and Outlook

The drilling industry in the U.S. Gulf Coast is highly cyclical and is typically driven by general economic activity and changes in actual or anticipated oil and gas prices. We believe that both our earnings and demand for our rigs will typically be correlated to our customers’ expectations of energy prices, particularly natural gas prices, and that sustained energy price increases will generally have a positive impact on our earnings.

We believe there are several trends that should benefit our operations, including:

	•		High Natural Gas Prices. While U.S. natural gas prices are volatile, the rolling twelve-month average price of natural gas has increased from $2.11 in January 1994 to $6.31 in June 2005. We believe high natural gas prices in the United States, if sustained, should result in more exploration and development drilling activity and higher utilization and dayrates for drilling companies like us.

	•		Need for Increased Natural Gas Drilling Activity. From 1995 to 2004, U.S. demand for natural gas grew at an annual rate of 0.7% while its supply grew at an annual rate of 0.2%. We believe that this supply and demand growth imbalance will continue if demand for natural gas continues to increase and production decline rates continue to accelerate. Even though the number of U.S. gas wells drilled has increased overall in recent years, a corresponding increase in production has not been realized. We believe that an increase in U.S. drilling activity will be required for the natural gas industry to meet the expected increased demand for, and compensate for the slowing production of, natural gas in the United States.

	•		Trend Towards Drilling Deeper Shallow Water Gas Wells. A current trend by oil and gas companies is to drill deep gas wells along the U.S. Gulf Coast in search of new and potentially prolific untapped natural gas reserves. We believe that this trend towards deeper drilling will benefit premium jackup rigs as well as barge rigs and submersible rigs that are capable of drilling deep gas wells. In addition, this trend will indirectly benefit conventional jackup fleets as the use of premium rigs in the U.S. Gulf Coast to drill deep wells should reduce the supply of rigs available to drill conventional wells.

	•		Redeployment of Jackup Rigs. Greater demand for jackup rigs in international areas over the last three years has reduced the overall supply of jackups in the U.S. Gulf of Mexico. This has created a more favorable supply environment for the remaining jackups, including ours. This favorable supply environment has contributed to increased jackup utilization and dayrates.

In response to the improved market conditions, our competitors and speculators have recently begun ordering new jackup drilling rigs. We believe there are currently 39 jackup rigs on order with delivery dates ranging from 2005 to 2008. Most of the rigs on order are premium cantilevered drilling units with 350 to 400 foot water depth capability. This trend of new jackup construction could curtail a further strengthening of utilization and dayrates, or reduce them.

Market conditions for our U.S. Gulf Coast jackup fleet improved beginning in the third quarter of 2003 and continued through the second quarter of 2005. As shown in the following table, from the second quarter of 2004 through the second quarter of 2005, our average revenue per day for U.S. Gulf of Mexico jackups and submersibles improved by 66%. During the same period, average revenue per day for our U.S. inland barges improved by 24%. As of July 18, 2005, our 12 marketed jackup rigs working in the U.S. Gulf Coast were contracted at dayrates ranging from $44,400 to $55,000. As of July 18, 2005, our 15 marketed inland barges were contracted at dayrates ranging from $20,400 to $34,500. We anticipate that the declining jackup rig supply in the U.S. Gulf Coast due to the redeployment of rigs to international locations, and the trend towards more deep gas well drilling will continue to result in higher utilization and dayrates.

The following table shows our average rig revenue per day and utilization for the quarterly periods ended on or prior to June 30, 2005 with respect to each of our three drilling segments. Average rig revenue per day is defined as operating revenue earned per revenue earning day in the period. Utilization in the table below is defined as the total actual number of revenue earning days in the period as a percentage of the total number of calendar days in the period for all drilling rigs in our fleet.


	Three Months Ended
	June 30,			September 30,			December 31,			March 31,			June 30,			September 30,			December 31,			March 31,			June 30,
	2003			2003			2003			2004			2004			2004			2004			2005			2005
Average Rig Revenue Per Day:
U.S. Gulf Coast Jackups and Submersibles	$	20,200		$	22,900		$	26,700		$	30,600		$	30,700		$	33,800		$	39,900		$	44,600		$	51,000
U.S. Inland Barges		17,600			18,300			18,700			20,300			22,500			22,900			23,000			25,000			27,800
Other International		19,100			21,000			25,600			40,000			37,500			34,600			29,400			28,400			33,900
Utilization:
U.S. Gulf Coast Jackups and Submersibles		44	%		54	%		50	%		43	%		50	%		54	%		56	%		56	%		56	%
U.S. Inland Barges		39	%		38	%		40	%		40	%		42	%		45	%		46	%		46	%		51	%
Other International		44	%		38	%		28	%		29	%		29	%		33	%		39	%		56	%		55	%

In May 2005, we signed a contract with Angola Drilling Company Limited (“ADC”) to reactivate our cold stacked jackup rig, THE 185, for a two-year drilling contract with two one-year options. Following a shipyard reactivation and mobilization to Angola, THE 185 is expected to begin drilling operations in late August 2005 at a dayrate of approximately $59,000 per day. Reactivation costs are estimated to be approximately $7 million, of which ADC paid us a fee of $5.0 million prior to the rig departing for Angola in late July 2005.

In June 2005, we signed a 150-day contract with ChevronTexaco for THE 156 to work in Colombia upon completion of its current drilling contract in late August 2005. The contract will require a 21-day shipyard project for contract preparation work and a 20-day mobilization to Colombia, which is anticipated to cost approximately $5 to $6 million, most of which will be reimbursed by ChevronTexaco. THE 156 is expected to begin drilling operations in late October 2005 at a dayrate of approximately $60,000 per day.

In the third quarter of 2003, we were awarded contracts with PEMEX, the Mexican national oil company, for two of our jackup rigs and a platform rig. After upgrades to comply with contract specifications, one rig began operating on a 720-day contract in early November 2003 at a contract dayrate of approximately $42,000. The other jackup rig began operating in early December 2003 on a 1,081-day contract at a contract dayrate of approximately $39,000. The platform rig contract is 1,289 days in duration and began operating in December 2004 at a contract dayrate of approximately $29,000. Each of the contracts can be terminated by PEMEX on five days notice, subject to certain conditions.

In the third quarter of 2004, two of our land rigs began working in Venezuela under one-year term contracts at dayrates of $22,200 and $23,800, and another two land rigs were re-deployed during October and November 2004 under one-year contracts with Petroleos de Venezuela (“PDVSA”), the Venezuelan national oil company, at contract dayrates of approximately $22,000 each. In April 2005, we signed a 340-day contract for a land rig which is to begin working in Trinidad in mid-August 2005. The contracted dayrate for the Trinidad contract is approximately $21,000 per day.

During the third quarter of 2005, in addition to the reactivations and contract preparation work discussed above, we anticipate that three of our U.S. Gulf of Mexico jackup rigs scheduled for maintenance will be out of operation for a total of 70 days. We also anticipate that our jack up rig, THE 206 in Mexico, will be out of operation for 28 days and two of our U.S. Inland barge rigs will be out of operation for a total of 15 days for scheduled maintenance. In addition to these scheduled maintenance projects, we have had pay rate increases and implemented a safety and retention bonus program. As such, we expect our operating costs per rig to exceed our average 2004 levels by approximately $2,500 per day in our U.S. Gulf of Mexico segment and by approximately $1,500 per day in our U.S. Inland Barge segment.

With respect to our Venezuelan operations, political unrest has negatively impacted our results of operations there. As a result, we experienced some decline in utilization in Venezuela during the second half of 2003 through late 2004. We currently have four land rigs operating under contract in Venezuela. In January 2005, we retained Simmons & Company International to explore alternatives for the disposition of our Venezuelan land drilling business, which is not viewed by us as being core to our ongoing offshore drilling business. The evaluation may result in the sale of some or all of our Venezuelan assets.

In April 2005, we decommissioned Rig 62, which was damaged by a fire in 2003, and began salvaging any remaining useable equipment. The decommissioning of Rig 62 reduced our inland barge drilling rig fleet to 27 rigs and did not result in any impairment charge, nor have any material adverse effect on our consolidated results of operations, financial condition or cash flows.

Prior to October 2004, our principal insurance coverages for property damage, liability and occupational injury and illness were included in Transocean’s insurance program in accordance with the master separation agreement. Effective October 15, 2004, we changed our insurance program to an independent, stand-alone insurance program, that provides for significantly lower deductibles than those in our previous insurance program. Our current deductible level under the new hull and machinery and protection and indemnity policies is $1.0 million and $5.0 million per occurrence, respectively. Previously, our deductible level under each of these policies was $10.0 million per occurrence.

Results of Continuing Operations

The following table sets forth our operating days, average rig utilization rates, average rig revenue per day, revenues and operating expenses by operating segment for the periods indicated:


	For the Three Months Ended						For the Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
	(In millions except per day data)
U.S. Gulf of Mexico Segment:
Operating days		1,146			990			2,305			1,847
Available days(a)		2,063			2,002			4,133			4,004
Utilization(b)		56	%		50	%		56	%		46	%
Average rig revenue per day(c)	$	51,000		$	30,700		$	47,800		$	30,600
Operating revenues	$	58.5		$	30.4		$	110.2		$	56.6
Operating and maintenance expenses(d)		32.1			21.4			57.8			45.4
Depreciation		12.5			12.2			25.2			24.6
Gain on disposal of assets, net		(3.7	)		—			(3.7	)		(1.5	)
Operating income (loss)		17.6			(3.2	)		30.9			(11.9	)
U.S. Inland Barge Segment:
Operating days		1,256			1,147			2,458			2,237
Available days(a)		2,457			2,730			5,081			5,460
Utilization(b)		51	%		42	%		48	%		41	%
Average rig revenue per day(c)	$	27,800		$	22,500		$	26,400		$	21,400
Operating revenues	$	34.9		$	25.8		$	64.9		$	47.9
Operating and maintenance expenses(d)		24.7			21.0			47.0			42.3
Depreciation		5.9			5.6			11.6			11.2
Gain on disposal of assets, net		(1.8	)		(0.8	)		(2.6	)		(1.0	)
Operating income (loss)		6.1			—			8.9			(4.6	)
Other International Segment:
Operating days		719			475			1,428			942
Available days(a)		1,304			1,638			2,564			3,276
Utilization(b)		55	%		29	%		56	%		29	%
Average rig revenue per day(c)	$	33,900		$	37,500		$	31,200		$	38,700
Operating revenues	$	24.4		$	17.8		$	44.5		$	36.5
Operating and maintenance expenses(d)		22.9			14.2			38.4			30.2
Depreciation		4.3			4.9			8.7			9.8
(Gain) loss on disposal of assets, net		0.2			(0.3	)		0.5			(0.3	)
Operating loss		(3.0	)		(1.0	)		(3.1	)		(3.2	)
Delta Towing Segment:
Operating revenues	$	12.7		$	6.8		$	22.8		$	13.6
Operating and maintenance expenses(d)		6.8			4.5			12.2			10.1
Depreciation		1.2			1.3			2.4			2.6
General and administrative expenses		1.0			1.0			2.2			1.8
Gain on disposal of assets		(0.3	)		(0.8	)		(0.9	)		(1.8	)
Operating income		4.0			0.8			6.9			0.9
Total Company:
Rig operating days		3,121			2,612			6,191			5,026
Rig available days(a)		5,824			6,370			11,778			12,740
Rig utilization(b)		54	%		41	%		53	%		40	%
Average rig revenue per day(c)	$	37,700		$	28,300		$	35,500		$	28,100
Operating revenues	$	130.5		$	80.8		$	242.4		$	154.6
Operating and maintenance expenses(d)		86.5			61.1			155.4			128.0
Depreciation		23.9			24.0			47.9			48.2
General and administrative expenses		9.9			7.2			18.3			19.6
Gain on disposal of assets, net		(5.6	)		(1.9	)		(6.7	)		(4.6	)
Operating income (loss)		15.8			(9.6	)		27.5			(36.6	)

See notes on following page.


Notes to preceding table.

(a)		Available days are the total number of calendar days in the period for all drilling rigs in our fleet.

(b)		Utilization is the total number of operating days in the period as a percentage of the total number of calendar days in the period for all drilling rigs in our fleet.

(c)		Average rig revenue per day is defined as revenue earned per operating day for the applicable segment, and as total U.S. Gulf of Mexico, U.S. Inland Barge and Other International revenues per rig operating days for “Total Company”.

(d)		Excludes depreciation and general and administrative expenses.

Three Months Ended June 30, 2005 and 2004

Operating Revenues. Total operating revenue increased $49.7 million, or 62%, during the second quarter of 2005 as compared to the comparable period in 2004. Overall average rig revenue per day increased from $28,300 in the second quarter of 2004 to $37,700 in 2005. The increase in average rig revenue per day reflects the continued improvement of market conditions in the U.S. Gulf Coast, as well as the revenue contribution from our platform rig which began operating in Mexico in December 2004 and three land rigs which began operating in Venezuela in the last half of 2004. Average rig utilization for our overall drilling rig fleet increased to 54% for the second quarter of 2005 from 41% in the second quarter of 2004.

Operating revenues for our U.S. Gulf of Mexico segment increased $28.1 million, or 92%, during the second quarter of 2005 as compared to the same period in 2004. In the three months ended June 30, 2005, we continued to achieve higher average rig revenue per day for our jackup and submersible drilling fleet as a result of our success in obtaining contracts with our customers at higher dayrates in response to increased market demand and decreased jackup drilling rig supply in the U.S. Gulf of Mexico. Average revenue per day increased to $51,000 for the three months ended June 30, 2005, up from $30,700 for the three months ended June 30, 2004, which resulted in an additional $21.7 million in operating revenues. Results for the second quarter of 2005 also reflect higher utilization for our current rig fleet in this market, after giving effect to the transfers of the jackup drilling unit THE 156 back to the U.S. Gulf of Mexico segment from our Other International segment in the fourth quarter of 2004. This increase in utilization resulted in $2.0 million in additional operating revenues in the second quarter of 2005 as compared to the same period in 2004. The transfer of THE 156 from our Other International segment generated operating revenues of $4.4 million in the second quarter of 2005.

Operating revenues for our U.S. Inland Barge segment increased $9.1 million, or 35%, during the second quarter of 2005 as compared to the same period in 2004, due to higher average rig revenue per day and utilization. This market has continued to improve since the second quarter of 2004 with average rig revenue per day increasing from $22,500 for the second quarter of 2004 to $27,800 for the comparable period in 2005. This increase resulted in additional operating revenues of $6.6 million. Utilization of our inland barge fleet was 51% for the second quarter of 2005, as compared to 42% for the comparable period in 2004, which resulted in a $2.5 million increase in operating revenues.

Operating revenues for our Other International segment were $24.4 million for the second quarter of 2005 for an increase of $6.6 million, or 37%, over operating revenues for the second quarter of 2004. This increase reflects the commencement of operation of our platform rig in Mexico in late 2004 under a long-term contract and three additional land rigs in Venezuela. The operation of the platform rig contributed an additional $4.3 million in operating revenues during the second quarter of 2005, including the recognition of $1.5 million of stand-by revenue for 52 days we incurred waiting for the PEMEX platform to be completed. PEMEX agreed to pay this stand-by revenue in May 2005. Higher land rig utilization in Venezuela contributed an additional $7.0 million in operating revenues in the second quarter of 2005 compared to the same period in 2004. These favorable contributions were offset by the transfer of THE 156 from Venezuela to the U.S. Gulf of Mexico, which generated $4.6 million in operating revenue during the second quarter of 2004.

The operations of Delta Towing contributed $12.7 million in operating revenues during the second quarter of 2005, an increase of $5.9 million, or 87%, as compared to the second quarter of 2004. Improved U.S. Gulf Coast market conditions and increased demand for marine support vessels resulted in Delta Towing’s revenue increase.

Operating and Maintenance Expenses. Total operating and maintenance expenses increased $25.4 million, or 42%, in the second quarter of 2005 as compared to operating expenses of $61.1 million for the comparable period in 2004. Operating and maintenance expenses for our U.S. Gulf of Mexico segment were $10.7 million higher for the three months ended June 30, 2005 than the second quarter of 2004 primarily due to increased personnel costs of $3.0 million related to the increased utilization and increased wages in the second quarter of 2005 as compared to the second quarter of 2004. Personal injury claim costs were $2.4 million higher in the second quarter of 2005 as compared to the same period in 2004. We also incurred additional repair and maintenance costs of $1.7 million and $1.4 million more mobilization expense in the second quarter of 2005 compared to the comparable period in 2004. The relocation of THE 156 back to the U.S. Gulf of Mexico also contributed an additional $1.6 million in expense in the second quarter of 2005 as compared to the second quarter of 2004. During the second quarter of 2004, THE 156 operated in Venezuela. Our U.S. Inland Barge segment had $3.7 million higher operating and maintenance expenses in the second quarter of 2005 as compared to the second quarter of 2004 primarily due to higher personnel costs of $2.4 million and personal injury claim costs of $1.3 million in the second quarter of 2005 when compared to the second quarter of 2004.

Operating and maintenance expenses for our Other International segment were $8.7 million higher for the three months ended June 30, 2005 than the three months ended June 30, 2004. In Mexico, operating costs were $4.1 million higher due to our platform rig which began operations in late 2004 and incurred costs of $2.8 million in the second quarter of 2005 and higher costs of $1.3 million, principally due to labor costs related to our other operations in Mexico. In Venezuela, higher operating and maintenance expenses of $2.1 million were due to a $3.5 million increase from increased land rig utilization during the second quarter of 2005 and higher operating expenses incurred on Rig 40 of $1.0 million partially offset by the relocation of THE 156 back to the U.S. Gulf of Mexico which contributed $2.6 million in expenses in the second quarter of 2004. In preparation for the commencement of operations in Angola, we incurred $2.5 million in reactivation costs on THE 185 in the second quarter of 2005.

Delta Towing operating and maintenance expenses were $2.3 million higher for the three months ending June 30, 2005 when compared to the three months ending June 30, 2004, due to the increased utilization of marine support vessels in the Gulf of Mexico and the shallow waters of the Gulf Coast in response to increased market demand.

General and Administrative Expenses. General and administrative expenses were $9.9 million for the second quarter of 2005 as compared to $7.2 million for the comparable period in 2004. The $2.7 million increase in general and administrative expenses was due primarily to $0.9 million additional stock compensation expense, $0.9 million in higher labor costs and $0.9 million in higher professional, accounting and legal fees which included a secondary offering in May 2005, additional audit fees and Sarbanes-Oxley compliance work.

Gain on Disposal of Assets, Net. During the three months ended June 30, 2005, we realized net gains on disposal of assets of $5.6 million, primarily related to the sale of THE 192 ($3.7 million), sale of drill pipe and miscellaneous equipment ($1.8 million) and the sale of a marine support vessel by Delta Towing ($0.3 million). During the three months ended June 30, 2004, we realized net gains on disposal of assets of $1.9 million primarily related to the sale of drill pipe and miscellaneous equipment ($1.1 million) and the sale of three support vessels by Delta Towing ($0.8 million).

Interest Expense. Third party interest expense decreased $0.1 million in the second quarter of 2005 as compared to the comparable period in 2004 primarily due to lower debt balances maintained in the second quarter of 2005 as compared to the second quarter of 2005 resulting from the repayment of our 6.75% Senior Notes in April 2005.

Income Tax Expense (Benefit). The income tax expense of $5.7 million for the second quarter of 2005 is principally comprised of our obligation to Transocean under the tax sharing agreement and represents amounts we owe Transocean for the utilization of pre-IPO federal and state tax benefits, and represents an effective tax rate of 34.0%. For the three months ended June 30, 2004, our net loss generated a tax benefit of $3.1 million or a 30.8% effective tax rate which was lower than the federal tax rate due to a valuation allowance on the Delta Towing tax benefits generated during the second quarter of 2004.

Six Months Ended June 30, 2005 and 2004

Operating Revenues. Total operating revenues increased $87.8 million or 57% during the first half of 2005, as compared to the same period in 2004. The increase in operating revenues is primarily attributable to higher overall average rig revenue per day earned in 2005, as compared to the prior year period. Overall average rig revenue per day increased from $28,100 for the six months ended June 30, 2004 to $35,500 for the six months ended June 30, 2005. The increase in average rig revenue per day reflects the continued improvement of market conditions in the U.S. Gulf of Mexico and transition zone along the U.S. Gulf Coast, the revenue contribution from our platform rig which began operating in Mexico in December 2004 and three land rigs which began operating in Venezuela in the last half of 2004. Average rig utilization of 53% for the six months ended June 30, 2005 was up from 40% in the comparable period in 2004.

Operating revenues for our U.S. Gulf of Mexico segment increased $53.6 million or 95% in the six months ended June 30, 2005, as compared to the first half of 2004. In 2005, we achieved higher average rig revenue per day for our jackup and submersible drilling fleet, improving from $30,600 per day to $47,800. This resulted in an additional $36.5 million in operating revenues for the six months ended June 30, 2005, as compared to the same period in 2004. The increase in average rig revenue per day is the result of our success in obtaining contracts with our customers at higher dayrates in response to increased market demand. Results for the first half of 2005 also reflect higher utilization for our current rig fleet in this market, after giving effect to the transfer of the jackup drilling unit THE 156 from our Other International segment in the fourth quarter of 2004. This increase in utilization resulted in $8.5 million in additional rig revenues in the six months ended June 30, 2005, as compared to the same period in 2004. The transfer of THE 156 generated operating revenues of $8.6 million in the six months ended June 30, 2005.

Operating revenues for our U.S. Inland Barge segment increased $17.0 million or 35% in the six months ended June 30, 2005, as compared to the same period in the prior year, primarily due to higher average rig revenue per day achieved in 2005, as compared to 2004. Average rig revenue per day increased from $21,400 for the six months ended June 30, 2004 to $26,400 for the six months ended June 30, 2005, as a result of our successful marketing efforts in negotiating higher dayrates for our fleet of inland barges during 2005. The increase in average rig revenue per day resulted in additional revenues of $12.3 million for the six months ended June 30, 2005, as compared to the same period in 2004. Utilization of our inland barge fleet was 48% for the year-to-date period in 2005, as compared to 41% for the first six months of 2004, which resulted in $4.7 million additional operating revenues in the first six months of 2005, as compared to the same period in 2004.

Operating revenues for our Other International segment were $44.5 million for the six months ended June 30, 2005. The 22%, or $8.0 million, increase over operating revenues reported for the six months ended June 30, 2004 reflects commencement of operation of our platform rig in Mexico in late 2004 under a long-term contract and four additional land rigs in Venezuela. The operation of the platform rig contributed an additional $7.0 million in operating revenues during the six months ended June 30, 2005. Higher land rig utilization in Venezuela contributed an additional $12.1 million in operating revenues in the six months ended June 30, 2005 compared to the same period in 2004. These favorable contributions were offset by the transfer of THE 156 from Venezuela to the U.S. Gulf of Mexico, which generated $11.0 million in operating revenues for the six months ended June 30, 2004.

Our operating revenues for the first half of 2005 included $22.8 million related to the operation of Delta Towing’s fleet of U.S. marine support vessels which increased from $13.6 million during the first half of 2004 due to increased vessel utilization in response to improved market conditions.

Operating and Maintenance Expenses. Total operating and maintenance expenses increased $27.4 million, or 21%, in the first six months of 2005, as compared to operating expenses of $128.0 million for the same period in 2004. Operating and maintenance expenses for our U.S. Gulf of Mexico segment were $12.4 million higher for the six months ended June 30, 2005 than the six months ended June 30, 2004. The factors contributing to this increase were additional personnel costs of $3.6 million relating to the higher utilizations and wage increases in 2005, an increase in personal injury claim costs of $0.8 million, the relocation of THE 156 back to the U.S. Gulf of Mexico ($3.3 million) and increased mobilization expense ($1.4 million). Additionally, the first six months of 2004 included a $0.7 million reduction in operating expenses as the result of an insurance claim recovery for damage to one of our jackup rigs.

Operating and maintenance expenses for our U.S. Inland Barge segment were $47.0 million for the six months ended June 30, 2005, as compared to $42.3 million for the same period in 2004. This $4.7 million, or 11%, increase was primarily the result of increasing personnel costs ($3.3 million) and higher repair and maintenance expenses, primarily on Rig 64 before beginning a two-well contract, of $0.9 million.

Operating costs for our Other International segment for the first six months of 2005 increased $8.2 million, as compared to the same period in 2004. This increase was due to our platform rig in Mexico which began operations in December 2004 and incurred $5.0 million of expenses in the first six months of 2005. In addition, we incurred higher expenses on our other Mexico operations of $0.3 million for the period ended June 30, 2005 as compared to the same period ended June 30, 2004. Higher land rig utilization and increasing costs in Venezuela resulted in an increase of $8.4 million when comparing the first six months of 2005 to the same period in 2004. Reactivation of THE 185 for operations in Angola resulted in an additional $2.5 million in expense being incurred during the first six months of 2005. These additional expenses were partially offset by the transfer of THE 156 to our U.S. Gulf of Mexico operations which lowered expenses in our Other International segment by $7.3 million for the six months ended June 30, 2005 as compared to the same period ended June 30, 2004 and a $0.8 million reduction in a Venezuelan labor claim legal reserve due to favorable settlements.

Delta Towing operations incurred $12.2 million in operating costs for the six months ended June 30, 2005. This represented a $2.1 million, or 21%, increase over operating costs of $10.1 million recognized in the comparable period ending June 30, 2004, due to increased marine support vessel utilization.

General and Administrative Expenses. General and administrative expenses were $18.3 million for the six months ended June 30, 2005, as compared to $19.6 million for the comparable period in 2004. General and administrative expenses for the six months ended June 30, 2005 decreased $1.3 million, as compared to the same period in 2004, due primarily to the inclusion of $7.9 million of stock compensation expense associated with post-IPO grants of stock options and restricted stock awards in 2004. Comparable stock compensation expense in 2005 was $4.3 million. Additionally in 2004, we recognized a one-time $1.5 million stock compensation expense related to the modification of Transocean stock options held by some of our employees. In addition, administrative charges incurred under our transition services agreement with Transocean were $0.3 million lower in the six months ended June 30, 2005 when compared with the six months ended June 30, 2004. These decreases were offset by higher payroll costs of $1.9 million, higher professional, accounting and legal fees of $1.6 million and an increase in Delta Towing and other general and administrative expenses of $0.6 million.

Gain on Disposal of Assets, Net. During the first six months of 2005, we realized net gains on disposal of assets of $6.7 million related to the sale of our jackup rig, THE 192 ($3.7 million), the sale of drill pipe and miscellaneous equipment ($2.3 million) and four marine support vessels by Delta Towing ($0.9 million). During the six months ended June 30, 2004, we realized gains on disposal of assets of $4.6 million, primarily related to the sale of four marine support vessels by Delta Towing ($1.8 million), the settlement of an October 2000 insurance claim for one of our jackup rigs ($1.5 million) and the sale of drill pipe and miscellaneous equipment ($1.3 million).

Interest Expense. Third party interest expense and interest expense-related party decreased $3.2 million in the six months ended June 30, 2005, as compared to the same period in 2004, primarily due to lower debt balances owed to third parties and Transocean. In the first quarter of 2004, we completed the debt-for-equity exchange of all our remaining outstanding related party debt payable to Transocean and in the second quarter of 2005 we made payments of $7.7 million to retire our 6.75% Senior Notes.

Income Tax Expense (Benefit). The income tax expense of $9.2 million for the six months ended June 30, 2005 reflects a 32.4% effective tax rate and is principally comprised of our obligation to Transocean under the tax sharing agreement and represents amounts we owe Transocean for the utilization of pre-IPO federal and state tax benefits. Tax expense for the first half of 2005 includes the effect of recognizing an additional $7.7 million in pre-IPO deferred state tax liabilities that existed at the IPO date. The recognition of these pre-IPO deferred state tax liabilities resulted in a $7.7 million reduction in additional paid-in capital, $0.9 million of deferred state tax benefit and a $6.8 million increase in deferred tax liabilities. Without the effect of this deferred state tax benefit, the effective tax rate for the six months ended June 30, 2005, would have been 35.6%.

Under the tax sharing agreement, we are unable to reduce our federal tax benefit obligation owed to Transocean for the state tax benefits utilized. We are currently in discussions with Transocean regarding an amendment to the tax sharing agreement to receive a federal tax benefit for the state tax benefits we pay. We anticipate completing this amendment to the tax sharing agreement in the third quarter of 2005, which we anticipate will further reduce our effective tax rate for the remainder of 2005. For the six months ended June 30, 2004, our net loss generated a tax benefit of $13.3 million or a 30.9% effective tax rate, which was lower than the federal tax rate due to a valuation allowance on the Delta Towing tax benefits generated during the first half of 2004.

Financial Condition

At June 30, 2005 and December 31, 2004, we had total assets of $780.7 million and $761.4 million, respectively. The $19.3 million increase in assets during the first six months of 2005 is primarily attributable to an increase in cash and accounts receivable of $41.5 million and $26.9 million, respectively. These increases in assets were partly offset by depreciation of $47.9 million and $4.4 million in net amortization of deferred preparation and mobilization costs. Both of these increases are a result of the continually improving market conditions in our industry.

Liquidity and Capital Resources

Sources and Use of Cash

Six Months Ended June 30, 2005 Compared to Six Months Ended June 30, 2004. Net cash provided by operating activities for the six months ended June 30, 2005 and 2004 was $42.1 million and $4.9 million, respectively. The $37.2 million increase in net cash provided by operating activities is primarily attributable to an increase in net income of $48.8 million. Adjustments to reconcile net income to net cash provided by operating activities were lower in 2005, primarily due to a $5.1 million decrease in stock compensation expense recognized by us in the first six months of 2005 compared to the corresponding period in 2004 and the additional $2.1 million gain recorded in the first half of 2005 as compared to the first half of 2004. Our net income was favorably affected by the continuing improvement in the demand for shallow water drilling services which resulted in our dayrates increasing from $28,100 to $35,400 and our rig utilization percentages increasing from 40% to 53%.

Changes in operating assets and liabilities, net of effect of distributions to related parties, resulted in a $4.9 million reduction in cash for the year to date period ending June 30, 2005, compared to a $3.1 million reduction in the same period in 2004. This $1.8 million decrease is primarily the result of an increase of our accounts receivable due to the improving demand for drilling services and the resulting increase in dayrates and utilization offset by an increase in our outstanding accounts payable due to the increased business and higher income tax balances resulting from the higher revenues and income in the first six months of 2005 as compared to the first six months of 2004.

Net cash provided by investing activities was $1.2 million for the six months ended June 30, 2005, compared to $4.9 million provided by investing activities for the same period in 2004. The $3.7 million decrease in net cash provided by investing activities is a result of capital expenditures increasing $4.3 million for the first half of 2005 as compared to the first half of 2004, offset by an increase in cash proceeds from sales of assets of $0.6 million.

Net cash used in financing activities was $1.8 million for the year to date period ended June 30, 2005, as compared to $1.9 million for the same period in 2004. Financing activities included a net borrowing against our Venezuela line of credit of $1.0 million and proceeds of $3.7 million from the exercise of common stock options. These were offset by our repayment of our 6.75% Senior Note outstanding balance of $7.7 million.

Sources of Liquidity and Capital Expenditures

Our existing cash balances and cash flows from operating activities were our primary sources of liquidity for the six months ended June 30, 2005. Our primary sources of liquidity for the six months ended June 30, 2004 were asset sales and our existing cash balances. For the six months ended June 30, 2005, our primary uses of cash were operating costs, capital expenditures of $9.1 million and debt repayments of $9.8 million. For the six months ended June 30, 2004, our primary uses of cash were operating costs, capital expenditures of $4.8 million related to upgrades and replacements of equipment and the retirement of amounts owed under capital lease obligations. At June 30, 2005, we had $106.6 million in cash and cash equivalents.

We anticipate that we will rely primarily on internally generated cash flows to maintain liquidity. From time to time, we may also make use of our revolving line of credit for cash liquidity. In December 2003, we entered into a two-year, $75 million floating-rate secured revolving credit facility that declined to $60 million in December 2004. There were no amounts outstanding under this credit facility at June 30, 2005.

The facility is secured by most of our drilling rigs, our receivables and the stock of most of our U.S. subsidiaries and is guaranteed by some of our subsidiaries. Borrowings under the facility bear interest at our option at either (1) the higher of (A) the prime rate and (B) the federal funds rate plus 0.5%, plus a margin in either case of 2.50% or (2) the Eurodollar rate plus a margin of 3.50%. Commitment fees on the unused portion of the facility are 1.50% of the average daily balance and are payable quarterly. Borrowings and letters of credit issued under the facility are limited by a borrowing base equal to the lesser of (A) 20% of the orderly liquidated value of the drilling rigs securing the facility, as determined from time to time by a third party selected by the agent under the facility, and (B) the sum of 10% of the orderly liquidated value of the drilling rigs securing the facility plus 80% of the U.S. accounts receivable outstanding less than 90 days, net of any provision for bad debt associated with such U.S. accounts receivable.

Financial covenants include maintenance of the following:

	•		a ratio of (1) current assets plus unused availability under the facility to (2) current liabilities (excluding specified subordinated liabilities owed to Transocean) of at least 1.2 to 1,

	•		a ratio of total debt to total capitalization of not more than 20% (excluding specified subordinated liabilities owed to Transocean from debt but including those liabilities in total capitalization),

	•		tangible net worth plus specified subordinated liabilities owed to Transocean of not less than the sum of (1) $425 million plus (2) to the extent positive, 50% of net income after December 31, 2003,

	•		a ratio of (1) the orderly liquidation value of the drilling rigs securing the facility to (2) the amount of borrowings and letters of credit outstanding under the facility of not less than 3 to 1, and

	•		in the event liquidity (defined as working capital (excluding specified subordinated liabilities owed to Transocean) plus availability under the facility) is less than $25 million, a ratio of (1) EBITDA minus capital expenditures during the preceding 12 fiscal months to (2) interest expense (excluding interest on specified subordinated debt owed to Transocean) during such period of not less than 2 to 1.

The revolving credit facility provides, among other things, for the issuance of letters of credit that we may utilize to guarantee our performance under some drilling contracts, as well as insurance, tax and other obligations in various jurisdictions. The facility also provides for customary fees and expense reimbursements and includes other covenants (including limitations on the incurrence of debt, mergers and other fundamental changes, asset sales and dividends) and events of default (including a change of control) that are customary for similar secured non-investment grade facilities. We received a waiver from the lenders in our revolving credit facility to pay a special cash dividend of $1.00 per share on August 25, 2005.

Additionally, we entered into an unsecured line of credit with a bank in Venezuela in the third quarter of 2004 to provide a maximum of 4.5 billion Venezuela Bolivars ($2.1 million U.S. dollars at the current exchange rate at June 30, 2005) in order to provide local currency liquidity. Each draw on the line of credit is denominated in Venezuela Bolivars and is evidenced by a 30-day promissory note that bears interest at the then market rate as designated by the bank. The promissory notes are pre-payable at any time at our option. However, if not repaid within 30 days, the promissory notes may be renewed at mutually agreeable terms for an additional 30-day period at the then designated interest rate. There are no commitment fees payable on the unused portion of the line of credit, and the facility is reviewed annually by the bank’s board of directors.

At June 30, 2005, we had $1.0 million (2.1 billion Venezuela Bolivars) in borrowings outstanding with respect to the line of credit which bears interest at 17% per annum. This amount is reported as debt due within one year in our condensed consolidated balance sheet at June 30, 2005. There were no borrowings outstanding under this line of credit at December 31, 2004.

We expect capital expenditures to be approximately $16 million, without any additional rig reactivations, for 2005, primarily for rig refurbishments and the purchase of capital equipment. The timing and amounts we actually spend in connection with the reactivation of other selected rigs is subject to our discretion and will depend on market conditions and our cash flows. We would expect capital expenditures to increase as market conditions improve. Our ability to fund capital expenditures would be adversely affected if conditions deteriorate in our business, we experience poor results in our operations or we fail to meet covenants under the revolving credit facility described in the previous paragraph.

In our fleet of 64 drilling rigs, we currently have eight cold stacked jackup rigs, 12 cold stacked inland barge rigs and two cold stacked submersible rigs. As a result of recent increases in the cost of steel, drill pipe and drilling equipment, we have updated our reactivation cost estimates for our cold stacked rigs. We currently believe the costs to prepare our eight cold stacked jackup rigs for service is approximately $60 to $65 million. The estimated cost to reactivate our 12 cold stacked inland barge rigs is approximately $39 to $44 million and to reactivate our 2 submersible rigs the estimated cost is $12 to $15 million. These estimated amounts are subject to variables including further rig deterioration over time, the availability and cost of shipyard facilities, customer requirements, cost of equipment and materials and the actual extent of required repairs and maintenance. Actual amounts could vary substantially.

We anticipate that our available funds, together with our cash generated from operations and amounts that we may borrow, will be sufficient to fund our required capital expenditures, working capital and debt service requirements for the foreseeable future. Future cash flows and the availability of outside funding sources, however, are subject to a number of uncertainties, especially the condition of the oil and natural gas industry. Accordingly, these resources may not be available or sufficient to fund our cash requirements.

During the six months ended June 30, 2005, there were no material changes to the contractual obligations, including our scheduled debt maturities, reported in our Annual Report on Form 10-K as of December 31, 2004. In addition, there has been no material change during the first six months of 2005 to the surety bonds that guarantee our performance as it relates to drilling contracts, insurance, tax and other obligations in various jurisdictions.

Dividend Policy

It has been our policy since the IPO not to pay dividends but to instead reinvest earnings in our business. However, due to favorable market conditions, our unrestricted cash balances have grown to levels that exceed our foreseeable needs for cash held for reinvestment and unknown contingencies. Therefore, our board of directors declared a special cash dividend of $1.00 per share payable on August 25, 2005 to stockholders of record on August 15, 2005. Our board of directors will determine any change in our dividend policy, the payment of future dividends on our common stock, if any, and the amount of any dividends.

In connection with the special cash dividend and as contemplated by our long term incentive plans, our Executive Compensation Committee awarded special cash bonuses to holders of stock options under our long term incentive plans in the aggregate amount of approximately $750,000 to compensate them for any potential loss in option value.

Cautionary Statement About Forward — Looking Statements

This report contains both historical and forward-looking statements. All statements other than statements of historical fact are, or may be deemed to be, forward-looking statements. Forward-looking statements include information concerning our possible or assumed future financial performance and results of operations, including statements about the following subjects:

	•		our strategy,

	•		improvement in the fundamentals of the oil and gas industry,

	•		the supply and demand imbalance in the oil and gas industry,

	•		the correlation between demand for our rigs, our earnings and our customers’ expectations of energy prices,

	•		our plans, expectations and any effects of focusing on agreements and marine assets and drilling for natural gas along the U.S. Gulf Coast, pursuing efficient, low-cost operations and a disciplined approach to capital spending, maintaining high operating standards and maintaining a conservative capital structure,

	•		estimated tax benefits and estimated payments under our tax sharing agreement with Transocean,

	•		expected capital expenditures,

	•		expected general and administrative expense,

	•		refurbishment costs,

	•		our ability to take advantage of opportunities for growth and our ability to respond effectively to market downturns,

	•		sufficiency of funds for required capital expenditures, working capital and debt service,

	•		deep gas drilling opportunities,

	•		operating standards,

	•		payment of dividends,

	•		competition for drilling contracts,

	•		matters related to our letters of credit and surety bonds,

	•		future transactions with unaffiliated third parties, including the possible sale of our Venezuelan assets,

	•		matters relating to our future transactions and relationship with Transocean,

	•		payments under agreements with Transocean,

	•		liabilities under laws and regulations protecting the environment,

	•		results and effects of legal proceedings,

	•		future utilization rates,

	•		future dayrates, and

	•		expectations regarding improvements in offshore activity, demand for our drilling rigs, our plan to operate primarily in the U.S. Gulf Coast, operating revenues, operating and maintenance expense, insurance expense and deductibles, interest expense, debt levels and other matters with regard to our outlook.

Forward-looking statements in this Form 10-Q are identifiable by use of the following words and other similar expressions:

	•		“anticipate,”

	•		“believe,”

	•		“budget,”

	•		“could,”

	•		“estimate,”

	•		“expect,”

	•		“forecast,”

	•		“intent,”

	•		“may,”

	•		“might,”

	•		“plan,”

	•		“predict,”

	•		“project,” and

	•		“should.”

The following factors could affect our future results of operations and could cause those results to differ materially from those expressed in the forward-looking statements included in this Form 10-Q:

	•		worldwide demand for oil and gas,

	•		exploration success by producers,

	•		demand for offshore and inland water rigs,

	•		our ability to enter into and the terms of future contracts,

	•		labor relations,

	•		political and other uncertainties inherent in non-U.S. operations (including exchange controls and currency fluctuations),

	•		the impact of governmental laws and regulations,

	•		the adequacy of sources of liquidity,

	•		uncertainties relating to the level of activity in offshore oil and gas exploration and development,

	•		oil and natural gas prices (including U.S. natural gas prices),

	•		competition and market conditions in the contract drilling

	•		work stoppages,

	•		increases in operating expenses,

	•		extended delivery times for material and equipment,

	•		the availability of qualified personnel,

	•		operating hazards,

	•		war, terrorism and cancellation or unavailability of insurance coverage,

	•		compliance with or breach of environmental laws,

	•		the effect of litigation and contingencies,

	•		our inability to achieve our plans or carry out our strategy,

	•		the matters discussed in “Business — Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2004, and

	•		other factors discussed in this Form 10-Q.

Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those indicated. Stockholders should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement, and we undertake no obligation to publicly update or revise any forward-looking statements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We have exposure to foreign exchange and interest rate risk. There have been no material changes in market risk exposures from those disclosed in Item 7A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2004.

Item 4. Controls and Procedures

As of June 30, 2005, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective. Disclosure controls and procedures are controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

There have been no significant changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II

Item 1. Legal Proceedings

The Company has certain actions or claims pending that have been previously discussed and reported in the Company’s Annual Report on Form 10-K for the year ended December 31, 2004. There were no material developments in these previously reported matters during the quarter ended June 30, 2005. The Company and its subsidiaries are involved in a number of other lawsuits, all of which have arisen in the ordinary course of business. The Company does not believe that ultimate liability, if any, resulting from any such other pending litigation will have a material adverse effect on its consolidated results of operations, financial position or cash flows.

Item 4. Submission of Matters to a Vote of Security Holders

On May 10, 2005 TODCO held its Annual General Meeting of Stockholders. Matters considered at the meeting were the election of Class I Directors, approval of the TODCO Long Term Incentive Plan and approval of the TODCO 2005 Long Term Incentive Plan. Each of Messrs. Jan Rask, Thomas N. Amonett and Ms. Suzanne V. Baer were elected at the meeting and Messrs. Michael J. Talbert, Arthur Lindenauer, Thomas R. Hix, Thomas M Hamilton, R. Don Cash continued as directors after the meeting. The TODCO Long Term Incentive Plan and TODCO 2005 Long Term Incentive Plan were both approved by stockholders at the meeting. The following were the results of the voting:

ELECTION OF DIRECTORS


					ABSTENTIONS and
Name	Votes FOR		Votes WITHHELD		BROKER NO-VOTES
Mr. Thomas N. Amonett		53,592,278		1,380,076	0
Mr. Jan Rask		54,931,374		40,980	0
Ms. Suzanne V. Baer		54,932,075		40,279	0

TODCO LONG TERM INCENTIVE PLAN


FOR	AGAINST		ABSTAIN		BROKER NO-VOTE
44,043,357		455,991		492,976	9,980,030

TODCO 2005 LONG TERM INCENTIVE PLAN


FOR	AGAINST		ABSTAIN		BROKER NO-VOTE
41,897,303		2,602,545		492,476	9,980,030

Item 6. Exhibits

Exhibit Index


Exhibit		Filed Herewith or Incorporated
No.	Description	by Reference from:
3.1	Third Amended and Restated Certificate of Incorporation.	Exhibit 3.1 to Annual Report on Form 10-K for the year ended December 31, 2003

3.2	Amended and Restated By-Laws	Exhibit 3.2 to Annual Report on Form 10- K for the year ended December 31, 2003

3.3	Form of Certificate of Designation of Series A Junior Participating Preferred Stock (included as Exhibit A to Exhibit 3.3)	Included as Exhibit A to Exhibit 3.3 to Amendment 1 of Form S-1, Registration No. 333-101921, filed February 12, 2003

10.1	Form of Director Deferred Stock Unit Award Letter under the TODCO 2005 Long Term Incentive Plan	Exhibit 10.1 to Current Report on Form 8-K dated as of May 13, 2005

10.2	Underwriting Agreement dated May 13, 2005	Exhibit 1.1 to Current Report on Form 8-K dated as of May 13, 2005

31.1	Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer	Filed herewith

31.2	Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer	Filed herewith

^…32.1	Section 1350 Certification of Chief Executive Officer and Chief Financial Officer	Furnished herewith


…		Furnished, not filed, in accordance with Item 601(b)(32) of Regulation S-K.

SIGNATURES

Pursuant to the requirements of Section 13(a) or 15(d) 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 in Houston, Texas, on this 4^th day of August, 2005.


		TODCO


		/s/ T. Scott O’Keefe

		T. Scott O’Keefe Senior Vice President and Chief Financial Officer (on behalf of TODCO and as Principal Financial Officer)

Exhibit Index


Exhibit		Filed Herewith or Incorporated
No.	Description	by Reference from:
3.1	Third Amended and Restated Certificate of Incorporation.	Exhibit 3.1 to Annual Report on Form 10-K for the year ended December 31, 2003

3.2	Amended and Restated By-Laws	Exhibit 3.2 to Annual Report on Form 10- K for the year ended December 31, 2003

3.3	Form of Certificate of Designation of Series A Junior Participating Preferred Stock (included as Exhibit A to Exhibit 3.3)	Included as Exhibit A to Exhibit 3.3 to Amendment 1 of Form S-1, Registration No. 333-101921, filed February 12, 2003

10.1	Form of Director Deferred Stock Unit Award Letter under the TODCO 2005 Long Term Incentive Plan	Exhibit 10.1 to Current Report on Form 8-K dated as of May 13, 2005

10.2	Underwriting Agreement dated May 13, 2005	Exhibit 1.1 to Current Report on Form 8-K dated as of May 13, 2005

31.1	Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer	Filed herewith

31.2	Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer	Filed herewith

^…32.1	Section 1350 Certification of Chief Executive Officer and Chief Financial Officer	Furnished herewith


…		Furnished, not filed, in accordance with Item 601(b)(32) of Regulation S-K.

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents