UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

Commission File Number 1-31983

TODCO

(Exact name of registrant as specified in its charter)

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:

None

      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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K     þ

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

      The aggregate market value of the Class A common stock held by non-affiliates of the Registrant as of June 30, 2004, was $215,285,597.

      As of March 1, 2005, the Registrant had 60,453,010 shares of Class A common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

      Portions of the registrant’s definitive Proxy Statement to be filed with the Securities and Exchange Commission within 120 days of December 31, 2004, for its 2005 annual general meeting of stockholders are incorporated by reference into Part III of this Form 10-K.

TABLE OF CONTENTS

PART I

Overview

      TODCO is a leading provider of contract oil and gas drilling services, primarily in the U.S. Gulf of Mexico shallow water and inland marine region, an area that we refer to as the U.S. Gulf Coast. We have the largest fleet of drilling rigs in the U.S. Gulf Coast and believe that, as a result of our leading position and geographic focus, we are well-positioned to benefit from a potential increase in drilling activity associated with the search for natural gas in this region.

      We operate a fleet of 65 drilling rigs consisting of 28 inland barge rigs, 24 jackup rigs, three submersible rigs, one platform rig, and nine land rigs. Currently, 51 of these rigs are located in shallow and inland waters of the United States with the remainder in Mexico, Trinidad and Venezuela.

      Our core business is to contract our drilling rigs, related equipment and work crews on a dayrate basis to customers who are drilling oil and gas wells. We provide these services mainly to independent oil and gas companies, but we also service major international and government-controlled oil and gas companies. Our customers in the U.S. Gulf Coast typically focus on drilling for natural gas.

      We provide our 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:

      For information about the revenues, operating income, assets and other information relating to our business segments and the geographic areas in which we operate, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Notes 2 and 17 to our consolidated financial statements included in Item 8 of this report. For information about the risks and uncertainties relating to our business, see “— Risk Factors.”

      Our website address is www.theoffshoredrillingcompany.com. We make our website content available for information purposes only. It should not be relied upon for investment purposes, nor is it incorporated by reference in this Form 10-K. We make available on this website, free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form  8-K and amendments to those reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the Securities and Exchange Commission (“SEC”). The SEC maintains an Internet site (www.sec.gov) that

contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, including us.

      Our executive offices are located at 2000 W. Sam Houston Parkway South, Suite 800, Houston, Texas 77042, and our telephone number is (713) 278-6000.

IPO and Separation from Transocean

      We were incorporated in Delaware on July 7, 1997 as R&B Falcon Corporation. On January 31, 2001, we became an indirect wholly owned subsidiary of Transocean Inc. (“Transocean”) as a result of the merger transaction between us and Transocean (the “Transocean Merger”). Transocean and its affiliates are collectively referred to herein as Transocean. The merger was accounted for as a purchase, with Transocean as the accounting acquirer. Accordingly, the purchase price was allocated to our assets and liabilities based on estimated fair values as of January 31, 2001 with the excess accounted for as goodwill. The purchase price adjustments were “pushed down” to our consolidated financial statements. On December 13, 2002, we changed our name from R&B Falcon Corporation to TODCO.

      In July 2002, Transocean announced plans to divest its Gulf of Mexico shallow and inland water (“Shallow Water”) business through an initial public offering of TODCO common stock. During 2003, we completed the transfer to Transocean of all assets not related to our Shallow Water business (“Transocean Assets”), including the transfer of all revenue-producing Transocean Assets. Accordingly, the Transocean Assets and related operations have been reflected as discontinued operations in our historical financial statements.

      In February 2004, we completed an initial public offering in which Transocean sold 13,800,000 shares of our Class A common stock (the “IPO”). Secondary stock offerings were completed in September 2004 and December 2004 where Transocean sold an additional 17,940,000 and 14,950,000 shares, respectively, of TODCO Class A common stock. At the closing of the December 2004 stock offering, Transocean converted all of its unsold shares of Class B common stock into an equal number of shares of Class A common stock. As a result of the above transactions, at December 31, 2004, Transocean owned 13,310,000 shares or approximately 22 percent of the outstanding Class A common stock of the Company. As a result of the conversion, no Class B common stock was outstanding as of December 31, 2004. We did not receive any proceeds from the IPO or the secondary offerings. See Note 3 in the accompanying Notes to Consolidated Financial Statements included in Item 8 of this report for further discussion.

      Effective February 23, 2005, Transocean notified us of its election to request us to file a “shelf” registration statement on Form S-3 to register the resale of up to 13,310,000 shares of our Class A common stock by Transocean on a delayed or continuous basis under Rule 415 of the Securities Act of 1933, as amended, pursuant to the Registration Rights Agreement between TODCO and Transocean. The Company will receive no proceeds from this offering.

      Prior to the IPO, we entered into several agreements with Transocean defining the terms of the separation of our business from the business of Transocean. These agreements included a Master Separation Agreement which defined our two businesses and provided for allocations of responsibilities and rights in connection therewith, a Tax Sharing Agreement which allocated certain rights and responsibilities with respect to pre and post IPO taxes, a Registration Rights Agreement pursuant to which we are required to file Registration Statements to assist Transocean in selling its shares of our common stock, an Employee Matters Agreement which governed the application of the separation of our employees from Transocean and its benefit plans and a Transition Services Agreement under which Transocean provided certain services to us during the initial phases of our separation from Transocean.

Drilling Rig Fleet

      Our drilling rig fleet consists of jackup rigs, barge rigs, and other rigs, which include submersible rigs, a platform drilling rig and land drilling rigs.

      There are several factors that determine the type of rig most suitable for a particular drilling operation. The most significant factors are water depth and seabed conditions (in offshore and inland marine environments), whether drilling is being done over a platform or other structure, and the intended well depth. Our fleet allows us to meet a broad range of needs in the shallow water along the U.S. Gulf Coast. Most of our drilling equipment is suitable for both exploration and development drilling, and we are normally engaged in both types of drilling activity. All of our mobile offshore drilling units are designed for operations away from port for extended periods of time and most have living quarters for the crews, a helicopter landing deck and storage space for pipe and drilling supplies.

      Following are brief descriptions of the types of rigs we operate. Rigs described in the following charts as “under contract” are operating under contract, including rigs being prepared or mobilized under contract. Rigs described as “warm stacked” are not under contract but are actively marketed and may require the hiring of additional crew (and, in some cases, an entire crew), but are generally ready for service with little or no capital expenditures. Rigs described as “cold stacked” are not actively marketed, generally cannot be ready for service immediately and normally require the hiring of an entire crew. Cold stacked rigs will also require a varying degree of maintenance and significant refurbishment before they can be operated. We include information in the following charts for rated drilling depth, which means drilling depth stated by the manufacturer of the drilling equipment. A rig may not have the actual capacity to drill to the rated drilling depth.

      Jackup rigs are mobile self-elevating drilling platforms equipped with legs that can be lowered to the ocean floor until a foundation is established to support the drilling platform. Once a foundation is established, the drilling platform is jacked further up the legs so that the platform is above the highest expected waves. The rig hull includes the drilling rig, jacking system, crew quarters, loading and unloading facilities, storage areas for bulk and liquid materials, helicopter landing deck and other related equipment.

      Jackup rig legs may operate independently or have a lower hull referred to as a “mat” attached to the lower portion of the legs in order to provide a more stable foundation in soft bottom areas. Independent leg rigs are better suited for harder or uneven seabed conditions while mat rigs are better suited for soft bottom conditions. Some of our jackup rigs have a cantilever design, a feature that permits the drilling platform to be extended out from the hull, allowing it to perform drilling or workover operations over some types of preexisting platforms or structures. Our other jackup rigs have a slot-type design, permitting the rig to be configured for drilling operations to take place through a slot in the hull. Slot-type rigs are usually used for exploratory drilling, since it is difficult to position them over existing platforms or structures. In the table below “ILC” means an independent leg cantilevered jackup rig, “MC” means a mat-supported cantilevered jackup rig and “MS” means a mat-supported slot-type jackup rig.

      The following table contains information regarding our jackup rig fleet as of March 1, 2005. For the rigs listed as cold stacked, we believe the estimated costs to prepare these rigs for service is approximately $40 to $45 million in the aggregate, based upon our latest estimates. 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.

      Barge drilling rigs are mobile drilling platforms that are submersible and are built to work in eight to 20 feet of water. They are towed by tugboats to the drill site with the derrick lying down. The lower hull is then submerged by flooding compartments until it rests on the river or sea floor. The derrick is then raised and drilling operations are conducted with the barge resting on the bottom. Our barge drilling fleet consists of conventional and posted barge rigs. A posted barge is identical to a conventional barge except that the hull and superstructure are separated by 10-to 14-foot columns, which increases the water depth capabilities of the rig. Most of our barge drilling rigs are suitable for deep gas drilling.

      The following table contains information regarding our barge drilling rig fleet as of March 1, 2005. For the rigs listed as cold stacked, we believe the estimated costs to prepare these rigs for service is approximately $33 to $38 million in the aggregate, based upon our latest estimates. 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.

     In the first quarter of 2005, we returned Rig 74 and Rig 75, which we bareboat chartered from a third party, to their owner.

      A submersible rig is a mobile drilling platform that is towed to the well site where it is submerged by flooding its superstructure until it rests on the sea floor, with the upper hull above the water surface. After

completion of the drilling operation, the rig is refloated by pumping the water out of the lower hull, so that it can be towed to another location. Submersible rigs typically operate in water depths of 12 to 85 feet. Our three submersible rigs are suitable for deep gas drilling.

      A platform drilling rig is placed on a production platform and is similar to a modular land rig. The production platform’s crane is capable of lifting the modularized rig crane that subsequently sets the rig modules. The assembled rig has all the drilling, housing and support facilities necessary for drilling multiple production wells. Most platform drilling rig contracts are for multiple wells and extended periods of time on the same platform. Once work has been completed on a particular platform, the rig can be redeployed to another platform for further work. We have one platform drilling rig.

      Our nine land drilling rigs are completely equipped to drill oil and gas wells. These rigs are designed to be transported by truck and assembled by crane. They require a firm, level area to be erected and sometimes require foundation work to be performed to support the drill floor and derrick.

      The following table contains information regarding our other rigs as of March 1, 2005. For the submersible rigs listed as cold stacked, we believe the estimated costs to prepare these rigs for service is approximately $7 to $8 million in the aggregate, based upon our latest estimates. 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.

     In December 2004, we made the decision to decommission our three lake barge rigs designed to work in Lake Maracaibo, Venezuela and to salvage any remaining useable equipment. As a result, we recorded a $2.8 million impairment loss on the three lake barges in December 2004.

Drilling Contracts

      Our contracts to provide drilling services are individually negotiated and vary in their terms and provisions. We obtain most of our contracts through competitive bidding against other contractors. Drilling contracts generally provide for payment on a dayrate basis, with higher rates while the drilling unit is operating and lower rates for periods of mobilization or when drilling operations are interrupted or restricted by equipment breakdowns, adverse environmental conditions or other factors.

      A dayrate drilling contract generally extends over a period of time covering the drilling of a single well or group of wells or covering a stated term. These contracts typically can be terminated by the customer under various circumstances such as the loss or destruction of the drilling unit or the suspension of drilling operations for a specified period of time as a result of a breakdown of major equipment. The contract term in some instances may be extended by the customer exercising options for the drilling of additional wells or for an additional term, or by exercising a right of first refusal.

      Historically, most of our drilling contracts have been short-term or on a well-to-well basis. From time to time, however, we enter into longer term drilling contracts. In the third quarter of 2003, we were awarded long-term 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 jackup 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.

Customers

      Our customers are primarily independent oil and gas companies, although we also work for large international oil companies and government-controlled oil companies. One customer, Applied Drilling Technologies, Inc., accounted for 11% of both our 2004 and 2003 operating revenues. No other customers accounted for 10% or greater of our operating revenues in 2004, 2003 or 2002. Nonetheless, the loss of any significant customer could, at least in the short term, have a material adverse effect on our results of operations.

Competitors

      The U.S. Gulf of Mexico shallow water and U.S. inland marine market segments in which we operate are highly competitive. We believe we are the second largest jackup rig contractor in the U.S. Gulf of Mexico shallow water market segment and the largest inland barge contractor in the U.S. inland marine market segment. In the U.S. inland marine market segment, our principal competitor is Parker Drilling Co. In the U.S. Gulf of Mexico shallow water market segment, we compete with numerous industry participants, none of which has a dominant market share. Drilling contracts are traditionally awarded on a competitive bid basis. Pricing is often the primary factor in determining which qualified contractor is awarded a job, although rig availability, safety record, crew quality and technical capability of service and equipment may also be considered. Many of our competitors in the U.S. Gulf of Mexico shallow water market segment have greater financial and other resources than we have and may be better able to make technological improvements to existing equipment or replace equipment that becomes obsolete.

Other Assets

      We have a 25% equity interest in Delta Towing, which operates a U.S. inland and shallow water marine support vessel business. Beta Marine LLC (“Beta Marine”) owns the remaining 75% equity interest in Delta Towing. In connection with its formation, Delta Towing issued notes to us with principal amounts totaling $144 million, secured by Delta Towing’s assets described in the following paragraph. Immediately prior to the closing of the merger with Transocean, we valued these notes at $80 million. Delta Towing has defaulted on its scheduled quarterly interest and principal payments on these notes. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Relationships with Variable Interest Entities.”

      Delta Towing owns and operates towing vessels and barges used primarily to transport and store equipment and material to support jackup and barge rig drilling operations. Delta Towing utilizes rig moving tugs, utility barges, service tugs and crew boats in connection with its operations. Although these assets can be deployed for other uses, a significant downturn in oil and gas activity in the transition zone would have a negative impact on Delta Towing’s business that could not be fully offset by deployment of such assets to other

markets. As of March 1, 2005, Delta Towing’s operating assets consisted of 50 inland tugs, 25 offshore tugs, 36 crewboats, 35 deck barges, 17 shale barges, five spud barges and three offshore barges.

      We also own additional offshore equipment that consists of five jackup rigs, three of which are mat-supported and two of which are independent leg rigs, ranging in water depth capacity from 100 feet to 160 feet, that we do not anticipate returning to drilling service as we believe doing so would be cost prohibitive. In May 2003, we decided to market these units for non-drilling uses such as production platforms or accommodation units. On March 1, 2005, we entered into an agreement to sell THE 192, a non-drilling jackup rig that was taken out of drilling service in May 2003. We expect this sale to close in April 2005, subject to customary closing conditions and to result in a gain of approximately $3.9 million.

Regulation

      Our operations are affected in varying degrees by governmental laws and regulations. The drilling industry is dependent on demand for services from the oil and gas industry and, accordingly, is also affected by changing tax and other laws relating to the energy business generally.

      The transition zone and shallow water areas of the U.S. Gulf of Mexico are ecologically sensitive. Environmental issues have led to higher drilling costs, a more difficult and lengthy well permitting process and, in general, have adversely affected decisions of oil and gas companies to drill in these areas. In the United States, regulations applicable to our operations include regulations controlling the discharge of materials into the environment, requiring removal and cleanup of materials that may harm the environment or otherwise relating to the protection of the environment. For example, as an operator of mobile offshore drilling units in navigable U.S. waters and some offshore areas, we may be liable for damages and costs incurred in connection with oil spills or other unauthorized discharges of chemicals or wastes resulting from or related to those operations. Laws and regulations protecting the environment have become more stringent, and may in some cases impose strict liability, rendering a person liable for environmental damage without regard to negligence or fault on the part of such person. Some of these laws and regulations may expose us to liability for the conduct of or conditions caused by others or for acts which were in compliance with all applicable laws at the time they were performed. The application of these requirements or the adoption of new requirements could have a material adverse effect on our financial position or results of operations.

      The U.S. Federal Water Pollution Control Act of 1972, commonly referred to as the Clean Water Act, prohibits the discharge of specified substances into the navigable waters of the United States without a permit. The regulations implementing the Clean Water Act require permits to be obtained by an operator before specified exploration activities occur. Offshore facilities must also prepare plans addressing spill prevention control and countermeasures. Violations of monitoring, reporting and permitting requirements can result in the imposition of civil and criminal penalties.

      The U.S. Oil Pollution Act of 1990 (“OPA”) and related regulations impose a variety of requirements on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills. Few defenses exist to the liability imposed by OPA, and the liability could be substantial. Failure to comply with ongoing requirements or inadequate cooperation in the event of a spill could subject a responsible party to civil or criminal enforcement action.

      The U.S. Outer Continental Shelf Lands Act authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the outer continental shelf. Included among these are regulations that require the preparation of spill contingency plans and establish air quality standards for certain pollutants, including particulate matter, volatile organic compounds, sulfur dioxide, carbon monoxide and nitrogen oxides. Specific design and operational standards may apply to outer continental shelf vessels, rigs, platforms, vehicles and structures. Violations of lease conditions or regulations related to the environment issued pursuant to the Outer Continental Shelf Lands Act can result in substantial civil and criminal penalties, as well as potential court injunctions curtailing operations and canceling leases. Such enforcement liabilities can result from either governmental or citizen prosecution.

      The U.S. Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes liability without regard to fault or the legality of the original conduct on some classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of a facility where a release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at a particular site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the cost of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. We could be subject to liability under CERCLA principally in connection with our onshore activities. It is also not uncommon for third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

      Our non-U.S. contract drilling operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to the importation of and operation of drilling units, currency conversions and repatriation, oil and gas exploration and development, taxation of offshore earnings and earnings of expatriate personnel, the use of local employees and suppliers by foreign contractors and duties on the importation and exportation of drilling units and other equipment. Governments in some foreign countries have become increasingly active in regulating and controlling the ownership of concessions and companies holding concessions, the exploration for oil and gas and other aspects of the oil and gas industries in their countries. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by major oil and gas companies and may continue to do so. Operations in less developed countries can be subject to legal systems that are not as mature or predictable as those in more developed countries, which can lead to greater uncertainty in legal matters and proceedings.

      Although significant capital expenditures may be required to comply with these governmental laws and regulations, such compliance has not materially adversely affected our earnings or competitive position.

Insurance

      Prior to October 15, 2004, our principal insurance coverage was included in Transocean’s insurance program. Under Transocean’s insurance program, we were provided with hull and machinery and protection and indemnity policies that each carried a deductible of $10.0 million per occurrence and provided primary coverage of $50 million, with several excess policies that extended coverage. The master separation agreement required Transocean to provide us with this insurance coverage until it no longer beneficially owned a majority of the voting power of our common stock. In addition, we were allowed to obtain insurance at our own expense at any time.

      Effective October 15, 2004, we implemented an independent, stand-alone insurance program. This new program provides for significantly lower deductibles than those in our previous insurance program with Transocean that we believe better matches our operations and asset base. The primary marine package provides for hull and machinery coverage with a $1.0 million deductible per occurrence, except in the event of a total loss, in which case there is no deductible. This policy provides coverage up to a scheduled value for the asset. The protection and indemnity coverage under the primary marine package has a $5.0 million deductible per occurrence with primary coverage up to $50 million. The primary marine package also provides coverage for cargo, control of well, seepage, pollution and property in our care, custody and control. In addition to our marine package, we have separate policies providing coverage for general domestic liability, employer’s liability, domestic auto liability and non-owned aircraft liability, with $250,000 deductibles per occurrence and primary coverage up to $50 million. We also have an excess liability policy that extends our coverage to an aggregate of $100 million under all of these policies. Our new insurance program includes separate policies that cover certain liabilities in foreign countries where we operate. Finally, our new insurance program provides coverage for certain specified environmental liabilities. Our basic marine package covers control of well, seepage and pollution care, custody and control. Our deductible for this coverage is $500,000 per occurrence.

      Insurance premiums under our new program will be approximately $7.5 million for the twelve-month policy period, or approximately $3.5 million higher than those under the previous program with Transocean. We expect that the increased premium cost will be more than offset by the benefit of the lower deductibles, primarily with respect to hull and machinery claims.

Employees

      As of March 1, 2005, we had approximately 1,970 employees. We require highly skilled personnel to operate and provide technical services and support for our drilling units. As a result, we conduct extensive personnel recruiting, training and safety programs.

      As of March 1, 2005, approximately 214 (or 11%) of our employees worldwide were working under collective bargaining agreements, approximately 48 of whom were working in Trinidad and 166 of whom were working in Venezuela. Efforts have been made from time to time to unionize other portions of our workforce, including workers in the Gulf of Mexico.

Risk Factors

      Our business, financial condition, results of operations and the trading prices of our securities can be materially and adversely affected by many events and conditions including the following:

Risks Related to Our Business

      Our business depends on the level of activity in oil and gas exploration, development and production primarily in the U.S. Gulf Coast (our term for the U.S. Gulf of Mexico shallow water and inland marine region) where we are active. Oil and gas prices and our customers’ expectations of potential changes in these prices significantly affect this level of activity. In particular, changes in the price of natural gas materially affect our operations because we primarily drill in the U.S. Gulf Coast where the focus of drilling has tended to be on the search for natural gas. Oil and gas prices are extremely volatile and are affected by numerous factors, including the following:

      Depending on the market prices of oil and gas, companies exploring for oil and gas may cancel or curtail their drilling programs, thereby reducing demand for drilling services. In the U.S. Gulf Coast, drilling contracts are generally short-term, and oil and gas companies tend to respond quickly to upward or downward changes in prices. Any reduction in the demand for drilling services may materially erode dayrates and utilization rates for our rigs and adversely affect our financial results.

      The U.S. Gulf Coast is a mature oil and gas production region that has experienced substantial seismic survey and exploration activity for many years. Because a large number of oil and gas prospects in this region have already been drilled, additional prospects of sufficient size and quality could be more difficult to identify. In addition, oil and gas companies may be unable to obtain financing necessary to drill prospects in this region. This could result in reduced drilling activity in the U.S. Gulf Coast region. We expect demand for drilling services in this area to continue to fluctuate with the cycles of reduced and increased overall domestic rig demand, and demand at similar points in future cycles could be lower than levels experienced in past cycles.

      Our industry is highly cyclical, with periods of high demand and high dayrates followed by periods of low demand and low dayrates. Periods of low rig demand intensify the competition in the industry and often result in rigs being idle for long periods of time. We may be required to idle rigs or enter into lower rate contracts in response to market conditions in the future. Due to the short-term nature of most of our drilling contracts, changes in market conditions can quickly affect our business. As a result of the cyclical nature of our industry, our results of operations have been volatile, and we expect this volatility to continue.

      The U.S. Gulf of Mexico shallow water and inland marine market segments in which we operate are highly competitive. Drilling contracts are traditionally awarded on a competitive bid basis. Pricing is often the primary factor in determining which qualified contractor is awarded a job. The competitive environment has intensified as recent mergers among oil and gas companies have reduced the number of available customers. Many other offshore drilling companies are larger than we are and have more diverse fleets, or fleets with generally higher specifications, and greater resources than we have. This allows them to better withstand industry downturns, better compete on the basis of price and build new rigs or acquire existing rigs, all of which could affect our revenues and profitability. We believe that competition for drilling contracts will continue to be intense in the foreseeable future.

      If as a result of improved industry conditions inactive rigs that are currently not being marketed are reactivated, jackup rigs or other mobile offshore drilling units are moved into the U.S. Gulf Coast or increased rig construction and rig upgrade programs by our competitors were to take place, a significant increase in the supply of jackups in the Gulf of Mexico could occur. A significant increase in the supply of jackup rigs or other mobile offshore drilling units could adversely affect both utilization and day rates.

      Most jackup and submersible rigs can be moved from one region to another, and in this sense the marine contract drilling market is a global market. The demand/supply balance for jackup and submersible rigs may vary somewhat from region to region, because the cost of a rig move is significant, there is limited availability of rig-moving vessels and some rigs are designed to work in specific regions. However, significant variations between regions tend not to exist on a long-term basis due to the ability to move rigs. Because many of our rigs were designed for drilling in the U.S. Gulf Coast, our ability to move our rigs to other regions in response to changes in market conditions is limited.

      Many of our competitors have jackup fleets with generally higher specification rigs than those in our jackup fleet. Particularly during market downturns when there is decreased rig demand, higher specification jackups and other rigs may be more likely to obtain contracts than lower specification jackups. As a result, our lower specification jackups have in the past been stacked earlier in the cycle of decreased rig demand than most of our competitors’ jackups and have been reactivated later in the cycle. This pattern has adversely

impacted our business and could be repeated. In addition, higher specification rigs have greater flexibility to move to areas of demand in response to changes in market conditions. Furthermore, in recent years, an increasing amount of exploration and production expenditures have been concentrated in deep water drilling programs and deeper formations, including deep gas prospects, requiring higher specification jackups, semisubmersible drilling rigs or drillships. This trend is expected to continue and could result in a decline in demand for lower specification jackup rigs like ours.

      Our operations are subject to the usual hazards inherent in the drilling of oil and gas wells, such as blowouts, reservoir damage, loss of production, loss of well control, punchthroughs, craterings, fires and pollution. The occurrence of these events could result in the suspension of drilling operations, claims by the operator, damage to or destruction of the equipment involved and injury or death to rig personnel. We may also be subject to personal injury and other claims of rig personnel as a result of our drilling operations. Operations also may be suspended because of machinery breakdowns, abnormal drilling conditions, failure of subcontractors to perform or supply goods or services and personnel shortages. In addition, offshore and inland marine drilling operators are subject to perils peculiar to marine operations, including capsizing, grounding, collision and loss or damage from severe weather. Damage to the environment could also result from our operations, particularly through oil spillage or extensive uncontrolled fires. We may also be subject to property, environmental and other damage claims by oil and gas companies. Our insurance policies and contractual rights to indemnity may not adequately cover losses, and we may not have insurance coverage or rights to indemnity for all risks. Moreover, pollution and environmental risks generally are not totally insurable.

      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. Insurance premiums under the new program will be approximately $7.5 million for the twelve-month policy period, or approximately $3.5 million higher than those under the previous program with Transocean. Insurance premiums and/or deductibles could be increased or coverages may be unavailable in the future.

      If a significant accident or other event, including terrorist acts, war, civil disturbances, pollution or environmental damage, occurs and is not fully covered by insurance or a recoverable indemnity from a customer, it could adversely affect our financial position or results of operations. Moreover, we may not be able to maintain adequate insurance in the future at rates we consider reasonable or be able to obtain insurance against certain risks.

      We are also from time to time involved in a number of litigation matters, including, among other things, contract disputes, personal injury, environmental, asbestos and other toxic tort, employment, tax and securities litigation, and other litigation that arises in the ordinary course of our business. Litigation may have an adverse effect on us because of potential adverse outcomes, the costs associated with defending the lawsuits, the diversion of our management’s resources and other factors.

      We require highly skilled personnel to operate and provide technical services and support for our drilling rigs. To the extent that demand for drilling services and the number of operating rigs increases, shortages of qualified personnel could arise, creating upward pressure on wages and difficulty in staffing rigs.

      Our success is to a considerable degree dependent on the services of our key management, including Jan Rask, our President and Chief Executive Officer. The loss of any member of our key management could adversely affect our results of operations.

      A small percentage of our employees worldwide work under collective bargaining agreements, all of whom work in Venezuela and Trinidad. Efforts have been made from time to time to unionize other portions of our workforce, including workers in the Gulf of Mexico. Any such unionization could increase our costs or limit our flexibility.

      Our operations are affected in varying degrees by governmental laws and regulations. The drilling industry is dependent on demand for services from the oil and gas industry and, accordingly, is also affected by changing tax and other laws relating to the energy business generally. We may be required to make significant capital expenditures to comply with laws and regulations. It is also possible that these laws and regulations may in the future add significantly to operating costs or may limit drilling activity.

      Our operations are subject to regulations that require us to obtain and maintain specified permits or other governmental approvals, control the discharge of materials into the environment, require the removal and cleanup of materials that may harm the environment or otherwise relate to the protection of the environment. For example, as an operator of mobile offshore drilling units in navigable U.S. waters and some offshore areas, we may be liable for damages and costs incurred in connection with oil spills or other unauthorized discharges of chemicals or wastes resulting from those operations. Laws and regulations protecting the environment have become more stringent in recent years, and may in some cases impose strict liability, rendering a person liable for environmental damage without regard to negligence or fault on the part of such person. Some of these laws and regulations may expose us to liability for the conduct of or conditions caused by others or for acts that were in compliance with all applicable laws at the time they were performed. The application of these requirements or the adoption of new requirements could have a material adverse effect on our financial position or results of operations.

      We operate in regions that may expose us to political and other uncertainties, including risks of:

      Our insurance policies and indemnity provisions in our drilling contracts generally do not protect us from loss of revenue. If a significant accident or other event occurs and is not fully covered by insurance or a recoverable indemnity from a customer, it could adversely affect our financial position or results of operations.

      Many governments favor or effectively require the awarding of drilling contracts to local contractors or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These practices may adversely affect our ability to compete.

      Our non-U.S. contract drilling operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to the equipment and operation of drilling units, currency conversions and repatriation, oil and gas exploration and development, taxation of offshore earnings and earnings of expatriate personnel, the use of local employees and suppliers by foreign contractors and duties on

the importation and exportation of drilling units and other equipment. Governments in some foreign countries have become increasingly active in regulating and controlling the ownership of concessions and companies holding concessions, the exploration for oil and gas and other aspects of the oil and gas industries in their countries. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by major oil and gas companies and may continue to do so. Operations in less developed countries can be subject to legal systems which are not as mature or predictable as those in more developed countries, which can lead to greater uncertainty in legal matters and proceedings.

      Another risk inherent in our operations is the possibility of currency exchange losses where revenues are received and expenses are paid in foreign currencies. We may also incur losses as a result of an inability to collect revenues because of a shortage of convertible currency available to the country of operation.

      A portion of our operations is conducted in the Republic of Venezuela, which has been experiencing political and economic turmoil, including labor strikes and demonstrations. The implications and results of the political, economic and social instability in Venezuela are uncertain at this time, but the instability could have an adverse effect on our business. Depending on future developments, we could decide to cease operations in Venezuela. Venezuela also imposes foreign exchange controls that limit our ability to convert local currency into U.S. dollars and transfer excess funds out of Venezuela. Although our current drilling contracts in Venezuela call for a significant portion of our dayrates to be paid in U.S. dollars, changes in existing regulation or the interpretation or enforcement of those regulations could further restrict our ability to receive U.S. dollar payments. The exchange controls could also result in an artificially high value being placed on the local currency.

Risks Related to Our Largest Stockholder Transocean

      Transocean will be permitted to transfer the shares of our common stock that it owns without allowing other stockholders to participate or realize a premium for their shares of common stock. Effective February 23, 2005, Transocean notified us of its election to request us to file a “shelf” registration statement on Form S-3 to register the resale of up to 13,310,000 shares of our Class A common stock by Transocean on a delayed or continuous basis under Rule 415 of the Securities Act of 1933, as amended, pursuant to the Registration Rights Agreement between TODCO and Transocean. A sale of a substantial amount of our common stock to a third party may adversely affect the market price of our common stock and our business and results of operations because the purchaser may be able to influence or change management decisions and business policy. Disclosure requirements in connection with the registration of such shares could affect our ability to engage in major acquisitions, mergers or other growth opportunities.

      As long as Transocean owns, directly or indirectly, a significant portion of the voting power of our outstanding common stock, Transocean will be able to exert significant influence over us as a result of contractual arrangements between us and Transocean and by virtue of Transocean’s voting power, including:

      In addition, without Transocean’s consent we may not amend our rights agreement or make any amendment to our amended and restated certificate of incorporation or bylaws that adversely affects Transocean, any of its affiliates or any transferee of any of its TODCO securities.

      Furthermore, even after Transocean no longer owns any shares of our common stock, Transocean will continue to have substantial control over our filing of tax returns so long as there remains a present or potential obligation for us to pay Transocean for pre-closing tax benefits.

      Because of exemptions granted under our rights agreement and because we have elected not to be subject to Section 203 of the General Corporation Law of the State of Delaware, Transocean, as a significant stockholder, may find it easier to sell its shares of our common stock to a third party than if we had not taken such actions.

      Our interests may conflict with those of Transocean in a number of areas relating to our past and ongoing relationships, including:

      We may not be able to resolve any potential conflicts with Transocean, and even if we do, the resolution may be less favorable than if we were dealing with an unaffiliated party. Our certificate of incorporation provides that Transocean has no duty to refrain from engaging in activities or lines of business similar to ours and that Transocean and its officers and directors will not be liable to us or our stockholders for failing to present specified corporate opportunities to us.

      Transactions and agreements we entered into after our acquisition by Transocean and on or before the closing of the IPO presented conflicts between our interests and those of Transocean. These transactions and agreements included the following:

      Because these transactions and agreements were entered into in the context of a parent-subsidiary relationship, their terms may be less favorable to us than the terms we could have obtained from an unaffiliated third party.

      Some of our executive officers and directors own Transocean ordinary shares or options to purchase Transocean ordinary shares which are of greater value than their ownership of our common stock and options. Ownership of Transocean ordinary shares by our directors and executive officers could create, or appear to create, potential conflicts of interest when directors and executive officers are faced with decisions that could have different implications for Transocean than they do for us.

      Some of our directors also serve as directors or executive officers of Transocean. These directors owe fiduciary duties to the shareholders of each company. As a result, in connection with any transaction or other relationship involving both companies, these directors may need to recuse themselves and not participate in any board action relating to these transactions or relationships.

      Our tax sharing agreement with Transocean provides that we must pay Transocean for substantially all pre-closing tax benefits utilized subsequent to the closing of the IPO. As of December 31, 2004, we had approximately $368 million of estimated pre-closing tax benefits subject to our obligation to reimburse Transocean. See Note 12 to our consolidated financial statements for the period ended December 31, 2004 included in Item 8 of this report.

      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 our outstanding voting stock, we will be deemed to have utilized all of these pre-closing tax benefits, and we will be required to pay Transocean an amount for the deemed utilization of these tax benefits adjusted by a specified discount factor. If an acquisition of beneficial ownership had occurred on December 31, 2004, the estimated amount that we would have been required to pay to Transocean would have been approximately $294 million, or 80% of the pre-closing tax benefits at December 31, 2004. In 2005, this percentage of remaining pre-closing tax benefits that would be payable to Transocean upon a change of beneficial ownership is reduced to 70%. Our requirement to make this payment could have the effect of delaying or preventing a change of control. The resulting payment to Transocean would be due even though we would not have derived, and may not in the future derive, a corresponding benefit. Our obligation to make a potentially substantial payment to Transocean may deter transactions that would trigger a payment under the tax sharing agreement, such as a merger in which we are not the surviving company or a merger in which more than 50% of the aggregate voting power of

our stock becomes owned by a single person or group of related persons. Even if we complete such a transaction, our obligation to make a substantial payment to Transocean could result in a lower economic benefit of such a transaction to our other stockholders than those stockholders could have received if we had not entered into the tax sharing agreement.

      Our tax sharing agreement with Transocean also provides that if any of our subsidiaries that join with us in the filing of consolidated returns ceases to do so, we will be deemed to have used that portion of any pre-closing tax benefits that will be allocable to the subsidiary following that cessation, and we will generally be required to pay Transocean the amount of this deemed tax benefit, adjusted by a specified discount factor, at the time the subsidiary ceases to join in the filing of these returns.

      Payment of amounts for the deemed utilization of tax benefits by us could require additional financing. The amount of our payments to Transocean will not be adjusted for any difference between the tax benefits that we are deemed to utilize and the tax benefits that we actually utilize, and the difference between these amounts could be substantial. Among other considerations, applicable tax laws may significantly limit our use of these tax benefits, and these limitations are not taken into account in determining the amount of the payment to Transocean. Additionally, Transocean’s right to receive this payment could result in a conflict of interest between us and Transocean and for those of our directors who are officers or directors of Transocean in considering any potential transaction.

      Our tax sharing agreement with Transocean provides that we must pay Transocean for most pre-closing tax benefits that we utilize on a tax return with respect to a period after the closing of the IPO. If the utilization of a pre-closing tax benefit defers or precludes our utilization of any post-closing tax benefit, our payment obligation with respect to the pre-closing tax benefit generally will be deferred until we actually utilize that post-closing tax benefit. This payment deferral will not apply with respect to, and we will have to pay currently for the utilization of pre-closing tax benefits to the extent of,

      Therefore, we may not realize the full economic value of tax deductions, credits and other tax benefits that arise post-closing until we have utilized all of the pre-closing tax benefits, if ever.

Other Risks

      Our net losses from continuing operations before cumulative effect of a change in accounting principle were approximately $29 million, $222 million and $529 million during the years ended December 31, 2004, 2003 and 2002, respectively, and we anticipate incurring substantial losses during future cyclical downturns in our industry. During cyclical downturns in our industry, we may need additional financing in order to satisfy our cash requirements. If we are not able to obtain financing in sufficient amounts and on acceptable terms, we may be required to reduce our business activities, seek financing on unfavorable terms or pursue a business combination with another company.

      We have no plans to pay regular dividends on our common stock. We generally intend to invest our future earnings, if any, to fund our growth. Any payment of future dividends will be at the discretion of our board of

directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends, and other considerations that our board of directors deems relevant. Our credit facility also includes limitations on our payment of dividends. Accordingly, investors may have to sell some or all of their common stock in order to generate cash flow from their investment. Investors may not receive a gain on their investment when they sell our common stock and may lose the entire amount of the investment.

      Our amended and restated certificate of incorporation and bylaws contain provisions that could delay or prevent a change of control or changes in our management that a stockholder might consider favorable. These provisions include:

We are also party to a rights agreement that could delay or prevent a change of control that a stockholder might consider favorable.

      We maintain our principal executive offices in Houston, Texas and have operational offices in Houma, Louisiana; Maturin, Venezuela; La Romaine, Trinidad and Ciudad del Carmen, Mexico. We also have warehouse and yard facilities in Abbeville, Louisiana; Houma, Louisiana; La Romaine, Trinidad and Maturin, Venezuela. We lease all of these facilities, except for the warehouse and yard facilities in Abbeville and Maturin.

      In October 2001, we were notified by the U.S. Environmental Protection Agency (“EPA”) that it had identified one of our subsidiaries 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 our review of our internal records to date, we dispute our designation as a potentially responsible party and do not expect that the ultimate outcome of this case will have a material adverse effect on our consolidated results of operations, financial position or cash flows. We continue to monitor this matter.

      Certain of our subsidiaries have been 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 we 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, we anticipate 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. We have not yet had an opportunity to conduct any discovery nor have we been able to determine the number of plaintiffs, if any, that were employed by our subsidiaries or Transocean’s subsidiaries or otherwise have any connection with our or Transocean’s drilling operations. We intend to defend ourselves vigorously and, based on the limited information available to us at this time, we do not expect the ultimate outcome of these lawsuits to have a material adverse effect on our consolidated results of operations, financial position or cash flows.

      Due to the limited information available to us at this time, we have not yet made a determination whether we or Transocean are financially responsible under the terms of the master separation agreement for any losses we 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 us for any losses we incur as a result of the legal proceedings described in the following four paragraphs.

      In December 2002, we received an assessment for corporate income taxes from SENIAT, the national Venezuelan tax authority, of approximately $20.7 million (based on current exchange rates and inclusive of penalties) relating to calendar years 1998 through 2001. In March 2003, we paid approximately $2.6 million of the assessment, plus approximately $0.3 million in interest, and are contesting the remainder of the assessment. After we made the partial assessment payment, we received a revised assessment in September 2003 of approximately $16.7 million (based on current exchange rates 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 March 1997, an action was filed by Mobil Exploration and Production U.S. Inc. and affiliates, St. Mary Land & Exploration Company and affiliates and Samuel Geary and Associates Inc. against our subsidiary Cliffs Drilling, its underwriters at Lloyd’s (the “Underwriters”) and its insurance broker in the 16th Judicial District Court of St. Mary Parish, Louisiana. The plaintiffs alleged damages in excess of $50 million in connection with the drilling of a turnkey well in 1995 and 1996. The case was tried before a jury in January and February 2000, and the jury returned a verdict of approximately $30 million in favor of the plaintiffs for excess drilling costs, loss of insurance proceeds, loss of hydrocarbons, expenses and interest. We and the Underwriters appealed such judgment, and the Louisiana Court of Appeals reduced the amount for which we may be responsible to less than $10 million. The plaintiffs requested that the Supreme Court of Louisiana consider the matter and reinstate the original verdict. We and the Underwriters also appealed to the Supreme Court of Louisiana requesting that the Court reduce the verdict or, in the case of the Underwriters, eliminate any liability for the verdict. Prior to the Supreme Court of Louisiana ruling on these petitions, we settled with the St. Mary group of plaintiffs and the State of Louisiana. Subsequently, the Supreme Court of Louisiana denied the applications of all remaining parties. We have been advised by Transocean that all claims against us have now been settled. As all costs related to this litigation, including settlement costs, were borne by Transocean, the settlements did not have a material adverse effect 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 our subsidiaries, in Tulsa, Oklahoma, the Greater Southwestern Funding Corporation (“Southwestern”) issued and sold, among other instruments, Zero Coupon Series B Bonds due 1999-2009 with an aggregate $189 million value at maturity. Paine Webber Incorporated (“Paine Webber”) 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 indemnifying 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 of 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. We dispute that there are any matters requiring us to indemnify Paine Webber. In any event, we do not expect that the ultimate outcome of this matter will have a material adverse effect on our consolidated results of operations, financial condition or cash flows.

      In April 2003, Gryphon Exploration Company (“Gryphon”) filed suit against some of our subsidiaries, Transocean and other third parties in the United States District Court in Galveston, Texas claiming damages in excess of $6 million. In its complaint, Gryphon alleges the defendants were responsible for well problems experienced by Gryphon with respect to a well in the Gulf of Mexico drilled by our subsidiaries in 2001. We have been advised by Transocean that this claim has now been settled. As all costs related to this litigation, including settlement costs, were borne by Transocean, the settlements did not have a material adverse effect on our consolidated results of operations, financial condition or cash flows.

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

      We cannot predict with certainty the outcome or effect of any of the litigation or regulatory matters specifically described above or of any other pending litigation. There can be no assurance that our beliefs 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.

      None during the fourth quarter of 2004.

PART II

      Our authorized capital stock consists of (1) 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 (2) 50,000,000 shares of preferred stock, par value $.01 per share. Of the 50,000,000 shares of preferred stock, 756,000 shares have been designated Series A preferred stock. At March 1, 2005, 60,453,010 shares of Class A common stock are outstanding. There are no outstanding shares of preferred stock or Class B common stock.

      Our Class A common stock is listed on the New York Stock Exchange (“NYSE”) under the symbol “THE.” As required by the listed company rules of the NYSE, our Chief Executive Officer certified to the NYSE on March 24, 2004 that he was not aware of any violation by TODCO of NYSE corporate governance listing standards as of that date.

      As of March 1, 2005, there were approximately 291 holders of record of our Class A common stock. We have presented in the table below, for the periods indicated, the reported high and low sales prices for our Class A common stock on the NYSE.

      On March 1, 2005, the last reported sales price of our Class A common stock was $24.16 per share.

      We have not paid any dividends since the completion of our IPO in February 2004 and we do not intend to declare or pay regular dividends on our common stock in the foreseeable future. Instead, we generally intend to invest any future earnings in our business. Subject to Delaware law, our board of directors will determine the payment of future dividends on our common stock, if any, and the amount of any dividends in light of any applicable contractual restrictions limiting our ability to pay dividends, our earnings and cash flows, our capital requirements, our financial condition, and other factors our board of directors deems relevant. Our credit facility includes limitations on our payment of dividends. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Historical Liquidity and Capital Resources — Sources of Liquidity and Capital Expenditures.”

      In February 2004, prior to our IPO, we exchanged $45,784,000 in principal amount of our outstanding 7.375% notes held by Transocean Holdings for 359,638 shares of our Class B common stock (4,367,714 shares of Class B common stock after giving effect to the stock dividend discussed below). Immediately following this exchange we exchanged $152,463,000 and $289,793,000 principal amount of our outstanding 6.75% and 9.5% notes, respectively, held by Transocean for 3,580,768 shares of our Class B common stock (43,487,535 shares of Class B common stock after giving effect to the stock dividend).

      The shares for debt exchanges were exempt from registration pursuant to Section 4(2) of the Securities Act of 1933. Immediately following these two exchanges, we declared a dividend of 11.145 shares of our Class B common stock with respect to each share of our Class B common stock outstanding immediately following the exchanges. As a result, 60,000,000 shares of our Class B common stock were issued and outstanding immediately prior to our IPO. Of those 60,000,000 Class B shares, 13,800,000 were converted to

Class A when these were sold in the IPO. The remaining 46,200,000 shares have since been converted into Class A common shares with Transocean having sold 17,940,000 and 14,950,000 shares in secondary public offerings completed in September 2004 and December 2004, respectively. Effective February 23, 2005, Transocean notified us of its election to request us to file a “shelf” registration statement on Form S-3 to register the resale of up to 13,310,000 shares of our Class A common stock by Transocean on a delayed or continuous basis under Rule 415 of the Securities Act of 1933, as amended, pursuant to the Registration Rights Agreement between TODCO and Transocean. We have not been, nor will be, the beneficiary of any proceeds from any offerings of our common stock by Transocean. See Note 3 to our consolidated financial statements included in Item 8 of this report

      The following table sets forth selected financial information for our company. The financial information for the years ended December 31, 2004, 2003 and 2002, and as of December 31, 2004 and 2003, has been derived from our audited financial statements included elsewhere in this report. The financial information for the year ended December 31, 2000, the one month ended January 31, 2001 and the eleven months ended December 31, 2001, and as of December 31, 2002, 2001 and 2000 has been derived from our audited financial statements not included in this report.

      The following selected historical financial data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and the related notes included in Item 8 of this report.

      On January 31, 2001, we became an indirect wholly owned subsidiary of Transocean as a result of our merger transaction with Transocean. The merger was accounted for as a purchase, with Transocean as the accounting acquirer. The purchase price was allocated to our assets and liabilities based on their estimated fair values on the date of the merger with the excess accounted for as goodwill. The purchase price adjustments were “pushed down” to our consolidated financial statements. Accordingly, our financial statements for periods subsequent to January 31, 2001 are not comparable to those of prior periods in material respects since those financial statements report financial position, results of operations and cash flows using a different basis of accounting.

Item 7.                          Management’s Discussion and Analysis of Financial Condition and Results of Operations

      The following discussion should be read in conjunction with our historical consolidated financial statements and the related notes included in Item 8 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:

      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, have 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.

      Operating and maintenance expenses may not necessarily fluctuate in proportion to changes in operating revenues because we generally 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:

      Market conditions for our U.S. Gulf Coast jackup fleet improved beginning in the third quarter of 2003 and continued through 2004. As shown in the following table, from the third quarter of 2003 through the fourth quarter of 2004, our average revenue per day for U.S. Gulf of Mexico jackups and submersibles improved by 74%. During the same period, average revenue per day for our U.S. inland barges improved by 26%. As of March 1, 2005, our 12 jackup rigs working in the U.S. Gulf Coast were contracted at dayrates ranging from $37,800 to $45,900. As of March 1, 2005, our 14 operating inland barges were contracted at dayrates ranging from $18,000 to $30,300. We anticipate that the declining jackup rig supply in the U.S. Gulf Coast and the trend towards more deep gas well drilling will continue to result in improved utilization and higher dayrates.

      With respect to our Venezuelan operations, political unrest has continued to negatively impact our results of operations there. As a result, we experienced some decline in utilization in Venezuela during the second half of 2003 and throughout 2004. In January 2005, we hired 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.

      The following table shows our average rig revenue per day and utilization for the quarterly periods ended on or prior to December 31, 2004 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, as adjusted to include calendar days available for rigs that were held for sale during the periods ended on or prior to December 31, 2002.

      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 cost to prepare the two jackup rigs to work in Mexico, including mobilization costs, which are deferred and will be recognized over the primary contract term, was approximately $22 million in the aggregate. The platform rig contract is 1,289 days in duration and began operating in December 2004 at a contract dayrate of approximately $29,000. Our platform rig was upgraded to

comply with PEMEX contract specifications at an aggregate cost of approximately $11 million. 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. Our jackup rig, THE 156 which began operating in Venezuela in mid-December 2003, completed its contract in September 2004 and has been relocated to the U.S. Gulf of Mexico.

      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. Insurance premiums under the new program will be approximately $7.5 million for the twelve-month policy period, or approximately $3.5 million higher than those under the previous program with Transocean. We expect that the increased premium cost will be more than offset by the benefit of the lower deductibles, primarily with respect to hull and machinery claims.

IPO and Separation from Transocean

      We were incorporated in Delaware on July 7, 1997 as R&B Falcon Corporation. On January 31, 2001, we became an indirect wholly owned subsidiary of Transocean as a result of the merger transaction between us and Transocean (the “Transocean Merger”). The merger was accounted for as a purchase, with Transocean as the accounting acquirer. Accordingly, the purchase price was allocated to our assets and liabilities based on estimated fair values as of January 31, 2001 with the excess accounted for as goodwill. The purchase price adjustments were “pushed down” to our consolidated financial statements, which affects the comparability of the consolidated financial statements for periods before and after the merger. Accordingly, the financial statements for the periods ended on or before January 31, 2001 were prepared using our historical basis of accounting and the financial statements for the periods subsequent to January 31, 2001 include the effects of the merger. On December 13, 2002, we changed our name from R&B Falcon Corporation to TODCO.

      In July 2002, Transocean announced plans to divest its Gulf of Mexico shallow and inland water (“Shallow Water”) business through an initial public offering of TODCO common stock. During 2003, we completed the transfer to Transocean of all assets not related to our Shallow Water business (“Transocean Assets”), including the transfer of all revenue-producing Transocean Assets. Accordingly, the Transocean Assets and related operations have been reflected as discontinued operations in our historical financial statements. See Note 21 to our consolidated financial statements included in Item 8 of this report.

      In February 2004, we completed our initial public offering in which Transocean sold 13,800,000 shares of our Class A common stock (the “IPO”). Secondary stock offerings were completed in September 2004 and December 2004 where Transocean sold an additional 17,940,000 and 14,950,000 shares, respectively, of TODCO Class A common stock. At the closing of the December 2004 stock offering, Transocean converted all of its unsold shares of Class B common stock into an equal number of shares of Class A common stock. As a result of the above transactions, at December 31, 2004, Transocean owns 13,310,000 shares or approximately 22 percent of the outstanding Class A common stock of the Company. As a result of the conversion, no Class B common stock is outstanding as of December 31, 2004. The Company received no proceeds from the IPO or the secondary stock offerings.

      Effective February 23, 2005, Transocean notified us of its election to request us to file a “shelf” registration statement on Form S-3 to register the resale of up to 13,310,000 shares of our Class A common stock by Transocean on a delayed or continuous basis under Rule 415 of the Securities Act of 1933, as amended, pursuant to the Registration Rights Agreement between TODCO and Transocean. The Company will receive no proceeds from the sale of these securities.

      Prior to the IPO, we entered into several agreements with Transocean defining the terms of the separation of our business from the business of Transocean. These agreements included a Master Separation Agreement which defined our two businesses and provided for allocations of responsibilities and rights in connection therewith, a Tax Sharing Agreement which allocated certain rights and responsibilities with respect to pre and post IPO taxes, a Registration Rights Agreement pursuant to which we are required to file Registration Statements to assist Transocean in selling its shares of our common stock, an Employee Matters Agreement which governed the application of the separation of our employees from Transocean and its benefit plans and a Transition Services Agreement under which Transocean provided certain services to us during the initial phases of our separation from Transocean.

Changes in Results of Operations Related to our Separation from Transocean

      As a result of our separation from Transocean, including the transfer of the Transocean Assets to Transocean in 2003 and the completion of our IPO in February 2004, our reporting of certain aspects of our results of operations differs from our historical reporting of results of operations. The following discussion describes these and other differences.

      General and administrative expense includes costs related to our corporate executives, corporate accounting and reporting, engineering, health, safety and environment, information technology, marketing, operations management, legal, tax, treasury, risk management and human resource functions. Prior to June 30, 2003 and the transfer of the Transocean Assets to Transocean, general and administrative expense also included an allocation from Transocean for certain administrative support. After June 30, 2003, general and administrative expense includes costs for services provided to us under our transition services agreement with Transocean. In addition, we are incurring additional general and administrative expense associated with the vesting of stock options and restricted stock granted in conjunction with the IPO.

      In February 2004, we adopted a long-term incentive plan for certain of our employees and non-employee directors in order to provide additional incentives through the grant of awards (the “Plan”). In conjunction with the closing of the IPO, we granted restricted stock and stock options to certain employees and non-employee directors. Additional awards were made during the year. Based upon the price per share at date of issuance, the value of these awards that we will recognize as compensation expense is approximately $17.5 million. We recognized $10.6 million of compensation expense related to these awards and grants during 2004. We will amortize the remaining $6.9 million to compensation expense over the vesting period of the awards and options. In addition to these grants under the Plan, we expect to make additional grants of restricted stock and stock options annually. The value of any additional awards under the Plan will be recognized as compensation expense over the vesting period of the awards.

      In addition, certain of our employees held options to acquire Transocean ordinary shares that were granted prior to the IPO. In accordance with the employee matters agreement, the employees holding such options were treated as terminated for the convenience of Transocean on the IPO date. As a result, these options became fully vested and were modified to remain exercisable over the original contractual life. In connection with the modification of the options, we recognized $1.5 million in additional compensation expense in the first quarter of 2004. No further compensation expense will be recognized related to the Transocean options.

      Interest income consists of interest earned on our cash balances and, for periods before December 31, 2003, on notes receivable from Delta Towing. Because of the adoption of the Financial Accounting Standards Board’s (“FASB”) Interpretation No. 46, Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51 (“FIN 46”) (see “— Relationships with Variable Interest Entities”), and the resulting consolidation of Delta Towing in our consolidated balance sheet effective December 31, 2003, we expect future interest income to consist of interest earned on our cash balances. For periods before the IPO, interest expense consisted of financing cost amortization and interest associated with our senior notes, other debt and other related party debt as described in the notes to our consolidated financial statements. After the closing of the IPO, interest expense primarily includes interest on the approximately $24 million face value of our senior notes payable to third parties, commitment fees on the unused portion of

our line of credit and the amortization of financing costs. Our debt levels and, correspondingly, our interest expense were substantially lower in 2004 compared to prior years as a result of the notes payable to Transocean prior to the IPO.

      In conjunction with the IPO, we entered into a tax sharing agreement with Transocean whereby Transocean will indemnify TODCO against substantially all pre-IPO income tax liabilities. However, we must pay Transocean for substantially all pre-closing income tax benefits utilized subsequent to the closing of the IPO. As of December 31, 2004, we had approximately $368 million of estimated pre-closing income tax benefits subject to this obligation to reimburse Transocean of which approximately $173 million of the tax benefits were reflected in our historical financial statements at December 31, 2003. 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-closing tax benefits and our corresponding obligation to Transocean may change when Transocean actually files its 2004 consolidated group tax return in 2005.

      As part of the tax sharing agreement, we must pay Transocean for substantially all pre-closing income tax benefits which we may utilize or be deemed to have utilized subsequent to the closing of the IPO. Accordingly, we recorded an equity transaction in 2004 to eliminate the valuation allowance associated with the pre-closing tax benefits and reflect the associated liability to Transocean for the pre-closing tax benefits as a corresponding obligation within the deferred income tax asset accounts. The net effect was a $181.4 million reduction in additional paid-in capital.

      In addition, Transocean agreed to indemnify us for certain tax liabilities that existed as of the IPO date, which are currently estimated to be $10.3 million. 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.

      We are currently in a net tax liability position for the year ended December 31, 2004 and expect to utilize a portion of the pre-closing income tax benefits to offset our federal income tax obligation. As of December 31, 2004, we have utilized $21.8 million of these pre-closing income tax benefits to offset our current federal income tax obligation resulting in a liability to Transocean of $7.6 million. Additionally in 2004, we utilized pre-closing state tax benefits resulting in a liability to Transocean of $0.8 million. Both of these liabilities are presented within accrued income taxes — related party in our consolidated balance sheet at December 31, 2004.

      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 our outstanding voting stock, we will be deemed to have utilized all of these pre-closing tax benefits, and we 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 we are unable to utilize the pre-closing tax benefits. If an acquisition of beneficial ownership had occurred on December 31, 2004, the estimated amount that the Company would have been required to pay Transocean would have been approximately $294 million, or 80% of the pre-closing tax benefits at December 31, 2004. In 2005, this percentage of remaining pre-closing tax benefits that would be payable to Transocean upon a change of beneficial ownership is reduced to 70%.

      We had an “ownership change” for purposes of Section 382 of the Internal Revenue Code of 1986, as amended, in connection with our secondary offering in September 2004. As a result, our ability to utilize certain of our tax benefits is subject to an annual limitation. However, we believe that, in light of the amount of the annual limitation, it should not have a material effect on our ability to utilize these tax benefits for the foreseeable future.

Critical Accounting Policies and Estimates

      Our discussion and analysis of our financial condition and results of operations is based on our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, operating revenues, expenses

and related disclosure of contingent assets and liabilities. On an ongoing basis, we evaluate our estimates, including those related to bad debts, materials and supplies obsolescence, investments, property, equipment and other long-lived assets, income taxes, workers’ injury claims, employment benefits and contingent liabilities. We base our estimates on historical experience and on various other assumptions we believe are reasonable under the circumstances. The results of these estimates form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates.

      We believe the following are our most critical accounting policies. These policies require significant judgments and estimates used in the preparation of our consolidated financial statements.

      Property and Equipment. Our property and equipment represent approximately 74% of our total assets as of December 31, 2004. We determine the carrying value of these assets based on our property and equipment accounting policies, which incorporate our estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values of our rigs. We review our property and equipment for impairment when events or changes in circumstances indicate that the carrying value of these assets or asset groups may be impaired or when reclassifications are made between property and equipment and assets held for sale as prescribed by the FASB’s Statement of Financial Accounting Standards (“SFAS”) 144, Accounting for Impairment or Disposal of Long-Lived Assets (“SFAS 144”). Asset impairment evaluations are based on estimated undiscounted cash flows for the assets being evaluated. Our estimates, assumptions and judgments used in the application of our property and equipment accounting policies reflect both historical experience and expectations regarding future industry conditions and operations. Using different estimates, assumptions and judgments, especially those involving the useful lives of our rigs and expectations regarding future industry conditions and operations, would result in different carrying values of assets and results of operations. For example, a prolonged downturn in the drilling industry in which utilization and dayrates were significantly reduced could result in an impairment of the carrying value of our drilling rigs.

      Allowance for Doubtful Accounts. We establish reserves for doubtful accounts on a case-by-case basis when we believe the collection of specific amounts owed to us is unlikely to occur. Our operating revenues are principally derived from services to U.S. independent oil and natural gas companies and international and government-controlled oil companies and our receivables are concentrated in the United States. We generally do not require collateral or other security to support customer receivables. If the financial condition of our customers deteriorates, we may be required to establish additional reserves.

      Provision for Income Taxes. Our tax provision is based on expected taxable income, statutory rates and tax planning opportunities available to us in the various jurisdictions in which we operate. Determination of taxable income in any jurisdiction requires the interpretation of the related tax laws. Our effective tax rate is expected to fluctuate from year to year as our operations are conducted in different taxing jurisdictions and the amount of pre-tax income fluctuates. Currently payable income tax expense represents either nonresident withholding taxes or the liabilities expected to be reflected on our income tax returns for the current year while the net deferred tax expense or benefit represents the changes in the balance of deferred tax assets and liabilities as reported on the balance sheet.

      Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized in the future. While we have considered estimated future taxable income and ongoing prudent and feasible tax planning strategies in assessing the need for the valuation allowances, changes in these estimates and assumptions, as well as changes in tax laws, could require us to adjust the valuation allowances for our deferred tax assets. These adjustments to the valuation allowance would impact our income tax provision in the period in which such adjustments are identified and recorded.

      Contingent Liabilities. We establish reserves for estimated loss contingencies when we believe a loss is probable and we can reasonably estimate the amount of the loss. Revisions to contingent liabilities are reflected in income in the period in which different facts or information become known or circumstances change that affect our previous assumptions with respect to the likelihood or amount of loss. Reserves for contingent liabilities are based upon our assumptions and estimates regarding the probable outcome of the

matter. Should the outcome differ from our assumptions and estimates, we would make revisions to the estimated reserves for contingent liabilities, and such revisions could be material.

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:

     Our consolidated results of operations for the year ended December 31, 2004 reflect the consolidation of our ownership interest in Delta Towing effective December 31, 2003 in accordance with FIN 46. Accordingly, our results for 2004 include revenues and expenses for Delta Towing. Prior to the adoption of FIN 46, we recorded our 25% interest in the results of Delta Towing as equity in income (loss) of joint venture in our consolidated statements of operations and also recognized interest income — related party related to Delta Towing’s notes payable to us. See “— Relationships with Variable Interest Entities” for a discussion of the effects of FIN 46 on our investment in Delta Towing.

      Revenues. Total revenues increased $123.7 million, or 54%, during 2004 as compared to 2003. The increase in revenues is primarily attributable to higher overall average rig revenue per day earned in 2004, and the inclusion of revenues from the operation of Delta Towing’s fleet of marine support vessels. Overall average rig revenue per day increased from $20,800 for 2003 to $29,100 for 2004. 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 addition of two of our jackup rigs which began operating offshore Mexico in late 2003 and a jackup rig that recently completed its contract offshore Venezuela. Average rig utilization of 43% for 2004 is up slightly from 41% average rig utilization in 2003. The increased utilization is principally due to a decrease in total available rig operating days in the 2004 period as a result of the removal of five jackup rigs from drilling service in the second quarter of 2003, partially offset by the effect of lower land rig utilization in Venezuela during 2004.

      Revenues for our U.S. Gulf of Mexico segment increased $40.0 million, or 40%, during 2004 as compared to 2003. In 2004, we achieved 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 $34,200 for 2004, up from $23,100 for 2003, which resulted in an additional $45.7 million in operating revenues for 2004 as compared to 2003. Results for 2004 also reflect higher utilization for our current rig fleet in this market, after giving effect to the transfers of the jackup drilling units THE 156, THE 205 and THE 206 to our Other International segment in the fourth quarter of 2003. This increase in utilization resulted in $8.9 million in additional rig revenues in 2004 as compared to 2003. The drilling units transferred to our Other International segment generated revenues of $14.6 million in 2003.

      Revenues for our U.S. Inland Barge segment increased $21.7 million, or 26%, in 2004 as compared to 2003, primarily due to higher average rig revenue per day. Average rig revenue per day increased from $18,500 for 2003 to $22,200 for 2004, as a result of our successful marketing efforts in negotiating higher dayrates for our fleet of inland barges during 2004. The increase in average rig revenue per day resulted in additional revenues of $17.9 million for 2004 as compared to 2003. This market has continued to improve in 2004 resulting in improved utilization of our inland barge fleet compared to utilization levels experienced beginning in the last half of 2003. Utilization of our inland barge fleet was 43% for 2004, as compared to 41% for 2003, which resulted in a $3.8 million increase in operating revenues in 2004.

      Revenues for our Other International segment were $73.3 million for 2004. The $31.0 million, or 73%, increase over operating revenues for 2003 reflects the operation of two of our jackup rigs, (THE 205 and THE 206), which began working offshore Mexico in late 2003 under long-term contracts and the operation of THE 156, which began operating under a multi-well contract with ConocoPhillips in late December 2003. The operation of these rigs in 2004 contributed an additional $41.9 million in operating revenues during 2004. The favorable contribution by these jackup rigs was partially offset by lower utilization for our land rigs in Venezuela and a platform rig in Trinidad that completed its contract in the third quarter of 2003. The lower utilization for our land rigs in Venezuela resulted in a $5.2 million decrease in operating revenues for 2004 as compared to 2003. Our platform rig, which was operating in Trinidad until the third quarter of 2003, generated $7.4 million of operating revenues in 2003.

      Our revenues for 2004 included $31.0 million related to the operation of Delta Towing’s fleet of U.S. marine support vessels.

      Operating and Maintenance Expenses. Total operating and maintenance expenses increased $32.3 million, or 14%, in 2004 as compared to operating expenses of $227.4 million for 2003. A decrease in operating expenses for our U.S. Gulf of Mexico and Inland Barge segments was offset by higher operating expenses in our Other International segment, primarily as a result of the three additional jackup rigs working in international locations in 2004 and the inclusion of $21.5 million in operating expenses related to Delta Towing. The decrease in operating expenses for our domestic segments for 2004 as compared to 2003, is primarily due to the transfer of three jackup drilling rigs from the U.S. Gulf of Mexico to international locations, the absence of one-time charges related to a well-control incident and a fire on two of our barge rigs and an insurance provision for damages sustained to the mat finger on one of our jackup rigs in 2003.

      Operating costs for our U.S. Gulf of Mexico segment declined $5.2 million, or 5%, in 2004 as compared to 2003, primarily due to the transfer of three of our jackup rigs to locations in Mexico and Venezuela in the fourth quarter of 2003 ($16.0 million) and an insurance provision in 2003 for damages sustained to one of our jackup rigs ($2.3 million). These favorable variances in operating costs were partly offset by higher costs for maintenance of our jackup rig fleet in the U.S. Gulf of Mexico ($6.1 million), increased labor costs ($2.7 million), higher reimbursable mobilization costs ($2.5 million), and increased personnel-related charges for labor and health benefits claims ($1.7 million) in 2004 as compared to 2003.

      Operating and maintenance expenses for our U.S. Inland Barge segment were $82.6 million for 2004 as compared to $95.8 million for 2003. Our results for 2003 included one-time charges of $7.5 million and $3.5 million related to a June 2003 well-control incident on Rig 62 and a September 2003 fire on Rig 20, respectively. The further decrease in operating expenses for this segment in 2004 as compared to 2003, was

due primarily to lower operating costs related to support vessels and other equipment rentals ($3.6 million), lower write-downs of other receivables ($0.7 million) and lower personal injury claims ($0.5 million). These favorable decreases were partly offset by $3.1 million in higher maintenance costs in 2004.

      Operating costs for our Other International segment for 2004 increased $29.2 million as compared to 2003, primarily due to $23.7 million of additional operating expenses as a result of our jackup drilling operations in Mexico. Operating expenses in 2004 also included $10.1 million of costs related to the operation of THE 156 offshore Venezuela through the third quarter of 2004. Our results for this segment in 2003 included $5.5 million of additional operating costs related to our platform rig in Trinidad, which completed its contract in the third quarter of 2003. Our platform rig began operating under a new contract in Mexico in late December 2004.

      General and Administrative Expenses. General and administrative expenses were $34.0 million for 2004 as compared to $16.3 million for 2003. The $17.7 million increase in general and administrative expenses was due primarily to the inclusion of $10.6 million of stock compensation expense associated with post-IPO grants of stock options and restricted stock awards, $1.5 million in stock compensation expense related to the modification of Transocean stock options held by some of our employees, $4.2 million in general and administrative expenses for Delta Towing and $2.4 million in higher other overhead costs, primarily related to corporate insurance policies and professional fees. These unfavorable variances in general and administrative expenses in 2004, as compared to 2003, were partly offset by lower administrative charges of $1.0 million for 2004 under our transition services agreement with Transocean, which became effective in the third quarter of 2003. See “— Related Party Transactions — Allocation of Administrative Costs.”

      Impairment Loss on Long-Lived Assets. During the fourth quarter of 2004, we recorded a $2.8 million non-cash impairment charge related to our decision to decommission our three Venezuelan lake barges and to salvage any remaining useable equipment. During the second quarter of 2003, we recorded a non-cash impairment charge of $10.6 million resulting from our decision to take five jackup rigs out of drilling service and market the rigs for alternative uses. We do not anticipate returning these rigs to drilling service, as we believe it would be cost prohibitive to do so. In conjunction with these decisions, and in accordance with SFAS 144, the carrying value of these assets was adjusted to fair market value. The fair market value of the drilling equipment on board the lake barges and the non-drilling rigs was primarily based on third party valuations. Additionally in the second quarter of 2003, we recorded a $1.0 million non-cash impairment resulting from our determination that assets of entities in which we had an investment did not support our recorded investment. The impairment was determined and measured based upon the remaining book value of the assets and our assessment of the fair value at the time the decision was made. In December 2003, we received $0.3 million in proceeds from certain assets sold by the entities, which was recorded as a reduction to the impairment charge. The entities were liquidated in early 2004.

      Gain on Disposal of Assets, Net. During 2004, we realized gains on disposal of assets of $6.5 million, primarily related to the sale of six marine support vessels by Delta Towing ($2.3 million), the settlement of an October 2000 insurance claim for one of our jackup rigs ($1.5 million), and sales and disposals of used drill pipe ($2.1 million). Net gains (losses) on disposal of assets were not significant in 2003.

      Interest Expense. Third party interest expense and interest expense-related party decreased $39.0 million in 2004 as compared to 2003, primarily due to lower debt balances owed to third parties and Transocean, partly offset by $1.2 million in bank commitment fees related to our $75 million line of credit entered into in December 2003. In 2003, we repaid $15.2 million of third party debt and, in conjunction with the transfer of the Transocean Assets, we retired $529.7 million in related party debt payable to Transocean. Additionally, prior to the closing of our IPO, we completed a debt-for-equity exchange of all our remaining outstanding related party debt payable to Transocean.

      Loss on Retirement of Debt. In conjunction with the retirement of debt held by Transocean in 2003, we recorded losses on retirement of related party debt in 2003 of $79.5 million. In the first quarter of 2004, we wrote off the remaining balance of unamortized fees of approximately $1.9 million associated with the exchange of Transocean debt for our outstanding senior notes in March 2002 due to the retirement of the debt in conjunction with the IPO. See “— Related Party Transactions — Long-Term Debt — Transocean.”

      Impairment of Investment in and Advance to Joint Venture. Based on cash flow projections and industry conditions, we recorded a $21.3 million impairment of our notes receivable from Delta Towing during the second quarter of 2003. See “— Relationships with Variable Interest Entities.”

      Other, Net. Other expense, net was $2.8 million for 2003, including a $2.4 million loss on revaluation of our local currency in Venezuela. In January 2003, Venezuela implemented foreign exchange controls that limited our ability to convert local currency into U.S. dollars and transfer excess funds out of Venezuela. The exchange controls caused an artificially high value to be placed on the local currency. As a result, we recognized a loss on revaluation of the local currency into functional U.S. dollars during the second quarter of 2003. In 2004, other income, net included $1.7 million in foreign currency exchange gains.

      Income Tax Benefit. The income tax benefit of $12.5 million for 2004 reflects an effective tax rate (“ETR”) of 30.2%, as compared to $50.1 million for 2003, based on an ETR of 18.5%. The increased ETR is primarily the result of providing a valuation allowance on net operating losses generated in 2003. During 2003, we recorded a valuation allowance on net operating loss carry forwards and foreign tax credits generated during the year. In 2004, to the extent we utilized net operating losses carry forwards (“NOL’s”) to reduce taxable income, we owe Transocean for the utilization of these NOL’s, in accordance with the tax sharing agreement. As of December 31, 2004, accrued income taxes payable to Transocean under the tax sharing agreement was $8.4 million. See “— Related Party Transactions — Other Transactions Between Us and Transocean.”

      Revenue. Total revenue increased $39.9 million, or 21%, during 2003 as compared to 2002. Overall average revenue per day and utilization increased slightly from $20,600 and 34%, respectively, in 2002 to $20,800 and 41%, respectively, in 2003. The increase in average revenue per day and utilization reflects improving market conditions in the U.S. Gulf of Mexico, as well as the addition of two of our jackup rigs which began operating offshore Mexico in late 2003 and a jackup rig that is currently working offshore Venezuela.

      Revenue for our U.S. Gulf of Mexico segment increased $35.5 million in 2003 as compared to 2002. Increased utilization for our jackup and submersible fleet for 2003 as compared to the prior year, increased revenue by $30.3 million. Additionally, we were able to achieve a slightly higher average revenue per day in this market segment in 2003, as compared to 2002, which resulted in an additional $6.9 million of operating revenues. This segment’s results for 2002 included $1.7 million relating to a jackup rig that was transferred to Transocean in the second quarter of 2002.

      Revenue for our U.S. Inland Barge segment decreased $3.3 million in 2003, as compared to 2002, primarily due to a lower average revenue per day earned by our fleet of barge rigs due to a continued softening in this market segment. The decrease in average revenue per day resulted in a $6.6 million decrease in revenue that was partly offset by an increase in revenue of $3.3 million due to increased utilization.

      The $7.7 million increase in revenue in 2003, as compared to 2002, for our Other International segment includes $3.5 million of revenue related to our two jackup rigs which began working offshore Mexico in late 2003 under long-term contracts and the effect of slightly higher utilization of our Venezuela rigs ($7.3 million), including the newly upgraded THE 156 which began operating under a 120-day contract with ConocoPhillips in late December 2003. These favorable variances were partly offset by the effect of lower average revenues per day earned by our Venezuela land rigs, which resulted in a $2.4 million decrease in revenues. Revenues attributable to our Trinidad rigs remained unchanged between the periods.

      Operating and Maintenance Expenses. Operating and maintenance expenses increased $41.7 million, or 22%, in 2003, as compared to 2002. Operating expenses in 2003 increased approximately $31 million associated with an increase in overall average utilization and client reimbursable costs. Operating costs for 2003 also included one-time charges relating to a well-control incident and fire on two of our inland barges ($11.0 million), a write-down of other receivables ($3.6 million) and an insurance provision for damages sustained to the mat finger on jackup rig THE 207 ($2.3 million). These increased costs were partially offset

by a decrease in the provision for doubtful accounts ($1.7 million) in 2003 as a result of the collection of amounts previously reserved, reduced expense relating to our insurance program in 2003 compared to 2002 ($2.9 million), lower expenses ($1.5 million) resulting from the transfer of a jackup rig to Transocean during the second quarter of 2002, and lower maintenance expenses related to our Trinidad operations.

      General and Administrative Expense. General and administrative expense decreased $12.6 million in 2003, as compared to 2002. This decrease in general and administrative expense was primarily attributable to lower allocations and charges from Transocean in 2003 for support provided related to the Transocean Assets ($8.3 million) since these assets had been sold or transferred prior to June 30, 2003 and a decrease in severance-related costs, other restructuring charges and compensation-related expenses incurred in 2002 ($4.4 million), with no comparable activity in 2003, associated with the late 2002 closure of our administrative office and warehouse in Louisiana and relocation of most of the operations and administrative functions to Houston, Texas. See “— Restructuring Charge.” Additionally, during 2002, we incurred $1.8 million of costs in connection with the exchange of our notes for Transocean Assets as more fully described in Note 6 of our consolidated financial statements included in Item 8 of this report. Partly offsetting these cost decreases were increased costs in 2003 related to the hiring of additional Houston-based staff to perform managerial and other administrative functions in connection with our anticipated separation from Transocean.

      Impairment Loss on Long-Lived Assets. During 2003, we recorded a non-cash impairment charge of $10.6 million resulting from our decision to take five jackup rigs out of drilling service and market the rigs for alternative uses. We do not anticipate returning these rigs to drilling service, as we believe it would be cost prohibitive to do so. As a result of this decision, and in accordance with SFAS 144, the carrying value of these assets was adjusted to fair market value. The fair market value of these units as non-drilling rigs was based on third party valuations. Additionally in 2003, we recorded a $1.0 million non-cash impairment resulting from our determination that assets of entities in which we have an investment did not support our recorded investment. The impairment was determined and measured based upon the remaining book value of the assets and our assessment of the fair value at the time the decision was made. These entities are currently in the process of being liquidated, and, in December 2003, we received $0.3 million in proceeds from certain assets sold by these entities, which was recorded as a reduction to the impairment charge.

      In 2002, we recorded non-cash impairment charges of $1.1 million relating to an asset held for sale. The impairment resulted from deterioration in market conditions and was determined and measured based on an estimate of fair market value derived from an offer from a potential buyer. In 2002, we also recorded non-cash impairment charges totaling $16.4 million relating to the reclassification of assets held for sale to assets held and used. The impairment of these assets resulted from management’s assessment that the assets no longer met the held for sale criteria under SFAS 144. In accordance with SFAS 144, the carrying value of these assets was adjusted to the lower of fair market value or carrying value adjusted for depreciation from the date the assets were classified as held for sale. The fair market value of the assets was based on third party valuations.

      Impairment Loss on Goodwill. As a result of our adoption of SFAS 142, Goodwill and Other Intangible Assets, as of January 1, 2002, goodwill is no longer amortized but reviewed at least annually for impairment. During the fourth quarter of 2002, we completed our annual impairment test and recognized a non-cash impairment of our remaining goodwill balance of $381.9 million. As of December 31, 2002, we had no goodwill balance. See Note 2 to our consolidated financial statements included in Item 8 of this report.

      Equity in Loss of Joint Ventures. In 2003, we recognized $6.5 million in equity losses related to our 25% ownership interest in Delta Towing as compared to equity losses of $3.2 million in 2002. The results for Delta Towing continue to be impacted by the downturn in the Gulf of Mexico oil and gas exploration and production market and related downturn in the energy services market, including the marine support vessel business, which has been slower to recover than other types of service providers. In addition, our 2003 results for Delta Towing include our share of a $2.5 million non-cash impairment charge on the carrying value of idle equipment recorded in the first quarter of 2003 and a December 2003 non-cash impairment charge of $1.9 million as a result of Delta Towing’s annual test of impairment of long-lived assets. See “— Relationships with Variable Interest Entities.”

      Our 2002 results reflect $0.5 million in earnings attributable to our other investments in unconsolidated affiliates, which were written off in 2003.

      Interest Income. Interest income decreased $32.7 million in 2003 as compared to 2002. Our 2002 results included $27.0 million of interest income related to our notes receivable from Transocean, which was repaid by Transocean in December 2002. In addition, we have previously recorded interest income related to our notes receivable from Delta Towing; however, in the second half of 2003 we established a reserve on interest earned on our notes receivable due to Delta Towing’s continued default on the notes. Interest income related to our notes receivable from Delta Towing decreased $3.3 million in 2003 as compared to 2002 as a result of this reserve. See “— Relationships with Variable Interest Entities” for a discussion of the effects of FIN 46 on our investment in Delta Towing.

      Interest Expense. The $55.6 million decrease in third party interest expense and interest expense-related party in 2003, as compared to 2002, is attributable to lower debt balances owed to third parties and Transocean. In 2003, we repaid $15.2 million of debt and, in conjunction with the transfer of the Transocean Assets, we retired $529.7 million in related party debt to Transocean during 2003.

      Loss on Retirement of Debt. In conjunction with the retirement of debt held by Transocean, we recorded a $79.5 million and $18.8 million loss on retirement of related party debt in 2003 and 2002, respectively. For a further discussion of these retirements, see “— Related Party Transactions” and Note 6 to our consolidated financial statements included in Item 8 of this report.

      Income Tax Benefit. The $24.5 million decrease in the income tax benefit for 2003 as compared to 2002 is the result of valuation allowances recorded on net operating loss carryforwards and foreign tax credits in 2003.

Discontinued Operations

      In July 2002, Transocean announced plans to divest its Shallow Water business through an initial public offering of TODCO common stock. During 2003, we completed the transfer to Transocean of the Transocean Assets, including all revenue-producing Transocean Assets. Accordingly, the Transocean Assets and related operations have been reflected as discontinued operations in our historical financial statements. See Note 21 to our consolidated financial statements included in Item 8 of this report for a discussion of discontinued operations.

Restructuring Charge

      In September 2002, we committed to a restructuring plan to consolidate some functions and offices. The plan resulted in the closure of an administrative office and warehouse in Louisiana and relocation of most of the operations and administrative functions previously conducted at that location to Houston, Texas. We established a liability of $1.2 million for the estimated severance-related costs associated with the involuntary termination of 57 employees pursuant to this plan. The charge was reported as operating and maintenance expense in our consolidated statements of operations for the year ended December 31, 2002. All severance-related costs were paid in 2002 and 2003. We do not currently expect other significant restructuring plans in the near term.

Cumulative Effect of a Change in Accounting Principle

      As a result of our adoption of FIN 46 as of December 31, 2003, we recognized a $0.8 million gain as a cumulative effect of a change in accounting principle related to our consolidation of Delta Towing. See “— Relationships with Variable Interest Entities.”

      During the year ended December 31, 2002, we recognized a non-cash impairment charge to goodwill of $1,363.7 million as a cumulative effect of a change in accounting principle related to the implementation of SFAS 142. Additionally, due to a general decline in market conditions and other factors, we recorded a $3,153.3 million impairment charge to goodwill related to our discontinued operations as a cumulative effect

of a change in accounting principle. For a discussion of changes in accounting principle, see Note 2 to our consolidated financial statements included in Item 8 of this report.

Financial Condition

      At December 31, 2004 and December 31, 2003, we had total assets of $761.4 million and $778.2 million, respectively. The $16.8 million decrease in assets during 2004 is primarily attributable to depreciation of $95.7 million, $2.0 million in net amortization of deferred preparation and mobilization costs, the write-off of $1.9 million in unamortized consent fees associated with the Transocean debt exchange offers and other net decreases in assets of $2.4 million. These decreases in assets were partly offset by $3.5 million in deferred income tax assets recognized during 2004, a $10.6 million increase in amounts receivable from Transocean in recognition of the post-IPO business and tax indemnities, an increase of $14.1 million in accounts receivable, trade and other and $45.1 million in higher cash and cash equivalents. The increase in our accounts receivable and cash was directly attributable to our increasing day rates throughout the year. See “— Liquidity and Capital Resources.” Total assets by business segment were as follows for the periods indicated below:

     Working capital at December 31, 2004 was $61.2 million, as compared to a working capital deficit of $3.8 million at December 31, 2003. The increase in working capital during 2004 is primarily attributable to our operating results for the year ended December 31, 2004, combined with the effect of lower cash interest payments as the result of the retirement of debt in 2003 and the pre-IPO debt-for-equity exchanges with Transocean.

Liquidity and Capital Resources

      The following discussion relates to our historical sources and uses of cash, which includes components from both continuing operations and discontinued operations resulting from our transfer of the Transocean Assets in 2003 and the retirement of the debt in conjunction with this transfer.

      2004 Compared to 2003. Net cash provided by operating activities was $57.7 million for the year ended December 31, 2004, as compared to $103.1 million in 2003. The $45.4 million decrease in net cash provided by operating activities is primarily attributable to lower adjustments to reconcile net loss as reported to net cash used in operating activities and less cash provided by changes in operating assets and liabilities, partly offset by a lower reported net loss for the year ended December 31, 2004 as compared to the year ended December 31, 2003. We reported a $257.4 million lower net loss in 2004, as compared to 2003, primarily due to the absence of net losses attributable to the Transocean Assets ($65.0 million) which were transferred to Transocean during 2003, a lower operating loss from continuing operations, lower net interest expense of $39.0 million and lower other non-cash charges in 2004. Total non-cash adjustments decreased $74.5 million for the year ended December 31, 2004, as compared to the year ended December 31, 2003. This was primarily the result of the loss on retirement of debt which was $77.6 million lower in 2004 compared to 2003 resulting from the debt related to the transfer of the Transocean Assets to Transocean in 2003, our impairment of advances to our joint venture with Delta Towing which resulted in a $21.3 million decrease and gains from

disposal of assets in 2004, an unfavorable effect on cash flows of $15.5 million. These were partially offset by favorable changes of $12.1 million related to stock-based compensation expense associated with our post-IPO stock option grants and restricted stock awards, as well as the modification of the Transocean stock options held by TODCO employees. In addition, favorable changes in our deferred income taxes of $13.6 million, deferred income change of $9.8 million and deferred expense change of $16.9 million related to our deferred mobilization and contract preparation costs contributed to offset the unfavorable changes discussed above. Changes in operating assets and liabilities, net of effect of distributions to affiliates, resulted in a $4.3 million reduction in cash in 2004, compared to a $224.0 million contribution in 2003. This $228.3 million decrease is primarily the result of the transfer of the Transocean Assets to Transocean and the related settlement of outstanding balances with Transocean. In addition, higher revenues in the fourth quarter of 2004 resulted in a significantly higher receivable balance at year end when compared to year end 2003.

      Net cash provided by investing activities was $0.4 million for the year ended December 31, 2004 compared to $59.5 million for the same period in 2003. The $59.1 million decrease in net cash provided by investing activities relates primarily to the sales of the Transocean Assets to Transocean which were completed by the end of the second quarter of 2003.

      Net cash used in financing activities was $13.0 million for the year ended December 31, 2004, as compared to $245.5 million for the same period in 2003. Financing activities in 2004 included an increase in restricted cash of $11.9 million related to performance bonds for our Mexico operations and capital lease payments of $1.1 million. Cash used in financing activities for the year ended December 31, 2003 included $103.9 million in cash balances transferred to Transocean in connection with the sale and distribution of subsidiaries to Transocean, the net repayment of long-term advances from Transocean of $54.0 million and $89.1 million in repayments of other debt. See “— Related Party Transactions.”

      Our cash flows from operations and asset sales were our primary sources of liquidity for the year ended December 31, 2004. Asset sales and our existing cash balances were our primary sources of liquidity for the year ended December 31, 2003.

      For the year ended December 31, 2004, our primary uses of cash were capital expenditures of $12.4 million related to upgrades and replacements of equipment, the use of $11.9 million for restricted cash to support our three performance bonds related to our Mexico operations and the retirement of amounts owed under capital lease obligations. Primary uses of cash for the year ended December 31, 2003 were debt repayments, including amounts due to Transocean, the transfer of cash balances in conjunction with the sale or distribution of Transocean Assets to Transocean and capital expenditures of $16.1 million for upgrades and replacements of equipment. At December 31, 2004, we had $65.1 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 December 31, 2004 and 2003.

      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:

      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.

      In the third quarter of 2004, we entered into an unsecured line of credit with a bank in Venezuela that provides for a maximum of 4.5 million Venezuela Bolivars ($2.3 million U.S. dollars at the current exchange rate at December 31, 2004) in order to establish a source of local currency to meet our current obligations in Venezuela Bolivars. 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. However, if not repaid within 30 days, the promissory notes automatically renew 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 terminable at will by the bank. At December 31, 2004, the Company had no borrowings outstanding under this line of credit.

      We expect capital expenditures to be approximately $15 million, without any rig activations, in 2005, primarily for rig refurbishments and the purchase of capital equipment. The timing and amounts we actually spend in connection with our plans to upgrade and refurbish other selected rigs, including rigs requiring substantial refurbishment, is subject to our discretion and will depend on our view of market conditions and our cash flows. We would expect capital expenditures to increase as market conditions improve. Our rigs requiring substantial refurbishment to be ready for service are noted in the tables in “Business — Drilling Rig Fleet.” From time to time we may review possible acquisitions of drilling rigs or businesses, joint ventures, mergers or other business combinations and may in the future make significant capital commitments for such purposes. Any such transactions could involve the issuance of a substantial number of additional shares or other securities or the payment by us of a substantial amount of cash. We would likely fund the cash portion, if any, of such transactions through cash balances on hand, the incurrence of additional debt, sales of assets, shares or other securities or a combination thereof. In addition, from time to time we may consider dispositions of drilling rigs. 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 above.

      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.

      As of December 31, 2004, our scheduled debt maturities and other contractual obligations are presented in the table below with debt obligations presented at face value:

      Prior to our IPO in February 2004, we exchanged $488.1 million principal amount of our outstanding senior note obligations payable to Transocean for shares of our Class B common stock. See “— Related Party Transactions — Long-Term Debt — Transocean.”

      At December 31, 2004, we had other commitments that we are contractually obligated to fulfill with cash should the obligations be called. These obligations represent surety bonds that guarantee our performance as it relates to our drilling contracts, insurance, tax and other obligations in various jurisdictions. These obligations could be called at any time prior to their expiration dates. The obligations that are the subject of these surety bonds are geographically concentrated in the United States, Mexico and Venezuela.

Derivative Instruments

      We have established policies and procedures for derivative instruments that have been approved by our board of directors. These policies and procedures provide for the prior approval of derivative instruments by our Chief Financial Officer and periodic review by the Audit Committee of our board of directors. From time to time, we may enter into a variety of derivative financial instruments in connection with the management of our exposure to fluctuations in foreign exchange rates and interest rates. We do not plan to enter into derivative transactions for speculative purposes; however, for accounting purposes, certain transactions may not meet the criteria for hedge accounting.

      Gains and losses on foreign exchange derivative instruments that qualify as accounting hedges are deferred as accumulated other comprehensive income and recognized when the underlying foreign exchange exposure is realized. Gains and losses on foreign exchange derivative instruments that do not qualify as hedges for accounting purposes are recognized currently based on the change in market value of the derivative instruments. At December 31, 2004, we did not have any outstanding foreign exchange derivative instruments.

      From time to time, we may use interest rate swaps to manage the effect of interest rate changes on future income. Interest rate swaps would be designated as a hedge of underlying future interest payments and would not be used for speculative purposes. The interest rate differential to be received or paid under the swaps is

recognized over the lives of the swaps as an adjustment to interest expense. If an interest rate swap is terminated, the gain or loss is amortized over the life of the underlying debt. At December 31, 2004, we did not have any outstanding interest rate swaps.

Relationships with Variable Interest Entities

      We own a 25% equity interest in Delta Towing, which was formed to own and operate our U.S. marine support vessel business consisting primarily of shallow water tugs, crewboats and utility barges. We contributed this business to Delta Towing in return for a 25% ownership interest and secured notes issued by Delta Towing with a face value of $144.0 million. No value was assigned to the ownership interest in Delta Towing. The note agreement was subsequently amended to provide for a $4.0 million, three-year revolving credit facility which has since been cancelled. Delta Towing’s property and equipment, with a net book value of $40.8 million at December 31, 2004, are collateral for our notes receivable from Delta Towing. The remaining 75% ownership interest is held by Beta Marine Services, L.L.C. (“Beta Marine”), which also loaned Delta Towing $3.0 million. See “— Related Party Transactions — Long-Term Debt — Beta Marine.”

      As a result of its issuance of notes to us, Delta Towing is highly leveraged. In January 2003, Delta Towing defaulted on the notes by failing to make its scheduled quarterly interest payments and remains in default as a result of its continued failure to make its quarterly interest payments, as well as a scheduled principal repayment due in January 2004. As a result of our continued evaluation of the collectibility of the notes, we recorded a $21.3 million impairment of the notes in June 2003 based on Delta Towing’s discounted cash flows over the terms of the notes, which deteriorated in the second quarter of 2003 as a result of the continued decline in Delta Towing’s business outlook. As permitted by the notes in the event of default, we began offsetting a portion of the amount owed by us to Delta Towing against the interest due under the notes. Additionally, in the third quarter of 2003, we established a $1.6 million reserve for interest income earned during the quarter on the notes receivable.

      In January 2003, the FASB issued FIN 46 which requires that an enterprise consolidate a variable interest entity (“VIE”) if the enterprise has a variable interest that will absorb a majority of the entity’s expected losses and/or receives a majority of the entity’s expected residual returns as a result of ownership, contractual or other financial interests in the entity, if such loss or residual return occurs. If one enterprise absorbs a majority of a VIE’s expected losses and another enterprise receives a majority of that entity’s expected residual returns, the enterprise absorbing a majority of the expected losses is required to consolidate the VIE and will be deemed the primary beneficiary for accounting purposes.

      Under FIN 46, Delta Towing is considered a VIE because its equity is not sufficient to absorb the joint venture’s expected future losses. TODCO is deemed to be the primary beneficiary of Delta Towing for accounting purposes because we have the largest percentage of investment at risk through the secured notes held by us and would thereby absorb the majority of the expected losses of Delta Towing. We have consolidated Delta Towing as of December 31, 2003. As of December 31, 2003, the consolidation of Delta Towing resulted in an increase in our net assets and a corresponding gain of $0.8 million which was presented as a cumulative effect of a change in accounting principle in our 2003 consolidated statement of operations.

      As of December 31, 2004 and 2003, we have eliminated in consolidation all intercompany account balances with Delta Towing as a result of the adoption of FIN 46, as well as the elimination of all intercompany transactions during the year ended December 31, 2004.

      Prior to December 31, 2003, we accounted for our investment in Delta Towing under the equity method and recorded $6.6 million and $3.2 million in equity losses for the years ended December 31, 2003 and 2002, respectively, as a reduction in the carrying value of Delta Towing’s notes receivable held by us. In addition, during the years ended December 31, 2002 and 2003, we earned interest income of $6.6 million and $3.3 million, respectively, on interest-bearing debt due from Delta Towing.

      During the year ended December 31, 2003 Delta Towing repaid approximately $1.8 million in related party debt owed to us.

      As part of the formation of the joint venture on January 31, 2001, we entered into a charter arrangement with Delta Towing under which we committed to charter for a period of 2.5 years from date of delivery 10 crewboats then under construction, all of which were in service as of December 31, 2004. We also entered into an alliance agreement with Delta Towing under which we agreed to treat Delta Towing as a preferred supplier for the provision of marine support services. During the year ended December 31, 2003, we incurred charges totaling $11.7 million from Delta Towing for services rendered which were reflected in operating and maintenance expense — related party. During the year ended December 31, 2002, we incurred charges totaling $10.7 million from Delta Towing for services rendered, of which $1.6 million was rebilled to our customers and $9.1 million was reflected in operating and maintenance expense — related party.

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

Related Party Transactions

      In connection with the acquisition of the marine business, Delta Towing entered into a $3.0 million note agreement with Beta Marine dated January 30, 2001. The note bears interest at 8%, payable quarterly. In January 2004, Delta Towing failed to make its scheduled principal payment to Beta Marine. The $3.0 million principal amount of the note payable has been classified as a current obligation in our consolidated balance sheet. During 2004, Delta Towing repaid a portion of accrued interest payable to Beta Marine from proceeds from the sales of marine vessels. We have no obligation to fund this debt on behalf of Delta Towing. Interest expense related to the note payable to Beta Marine was $0.3 million for the year ended December 31, 2004.

      Transocean has historically provided specified administrative support to us. Transocean has charged us a proportional share of its administrative costs based on estimates of the percentage of work each Transocean department performs for us. The amount of expense allocated to us was $1.4 million and $9.7 million for the years ended December 31, 2003 and 2002, respectively, and was classified as general and administrative — related party expense. Following the IPO, some of these functions were provided to us under the transition services agreement with Transocean. Charges under the transition services agreement amounted to $0.4 million for the year ended December 31, 2004 and are reported as general and administrative — related party expense. Transocean no longer provides significant services to us.

      We were party to a $1.8 billion two-year revolving credit agreement (the “Transocean Revolver”) with Transocean, dated April 6, 2001. During the years ended December 31, 2003 and 2002, we recognized $0.8 million and $1.8 million, respectively, in interest expense related to the Transocean Revolver. On April 6, 2003, the approximately $81.2 million then outstanding under the Transocean Revolver was converted to a 2.76% fixed rate promissory note issued by us to Transocean which was scheduled to mature on April 6, 2005. This note was cancelled in 2003 in connection with a series of transactions.

      In March 2002, together with Transocean, we completed exchange offers and consent solicitations for our 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, Transocean exchanged approximately $234.5 million, $342.3 million, $247.8 million, $246.5 million, $76.9 million and $289.8 million principal amount of our outstanding 6.5%, 6.75%, 6.95%, 7.375%, 9.125% and 9.5% Senior Notes, respectively (the “Exchanged Notes”), for newly-issued Transocean notes having the same principal amount, interest rate, redemption terms and payment and maturity dates. As of December 31, 2004, we had approximately $7.7 million, $2.2 million, $3.5 million and $10.2 million principal amount of the 6.75%, 6.95%, 7.375% and 9.5% Senior Notes, respectively, outstanding that were not exchanged in the Exchange Offer. Both the exchanged notes and the notes not exchanged remained our obligation. As a result of the consent payments made in connection with the Exchange Offer, interest expense for 2003 and 2002 increased by approximately $0.5 million and $1.3 million, respectively.

      In December 2002, we repurchased all of the approximately $234.5 million and $76.9 million principal amount outstanding of our 6.5% and 9.125% Exchanged Notes held by Transocean, respectively, and approximately $189.8 million principal amount outstanding of our 6.75% Exchanged Notes held by Transocean plus accrued and unpaid interest. We recorded a net after-tax loss of $12.2 million in conjunction with the repurchase of these notes. We funded the repurchase from cash received from Transocean’s repayment of approximately $518.0 million aggregate principal amount of outstanding notes receivable plus accrued and unpaid interest.

      During 2003, we sold to Transocean, in separate transactions, our investment in Arcade Drilling AS, Cliffs Platform Rig 1, our 50% interest in Deepwater Drilling LLC, our 60% interest in Deepwater Drilling II LLC and our membership interests in R&B Falcon Drilling (International & Deepwater) Inc. LLC. As consideration for the sale of these assets, Transocean cancelled $529.7 million principal amount outstanding of the Exchanged Notes.

      The book value of the Exchanged Notes was $522.0 million at December 31, 2003 and $980.1 million at December 31, 2002. We recognized $42.7 million and $77.9 million in interest expense related to these notes for the years ended December 31, 2003 and 2002, respectively.

      In February 2004, prior to the closing of our IPO, we exchanged $45.8 million in principal amount of our outstanding 7.375% Exchanged Notes held by Transocean Holdings, plus accrued interest thereon, for 359,638 shares of our Class B common stock (4,367,714 shares of Class B common stock after giving effect to the stock dividend). See “— Other Transactions Between Us and Transocean.” Immediately following this exchange, we exchanged $152.5 million and $289.8 million principal amount of our outstanding 6.75% and 9.5% Exchanged Notes, respectively, held by Transocean, plus accrued interest thereon, for 3,580,768 shares of our Class B common stock (43,487,535 shares of Class B common stock after giving effect to the 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 — related party and interest payable — 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. There were no Exchanged Notes payable to Transocean outstanding at December 31, 2004. We recognized $3.1 million in interest expense — related party associated with these notes prior to their cancellation in February 2004.

      In connection with the Exchange Offer, we made an aggregate of $8.3 million in consent payments to holders of our notes that were exchanged. The consent payments were amortized as an increase to interest expense over the remaining term of the respective exchanged notes using the interest method and such amortization totaled $0.5 million and $1.3 million for the years ended December 31, 2003 and 2002, respectively. In connection with the retirement of the Exchanged Notes prior to the completion of the IPO, we 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 our consolidated statement of operations for the year ended December 31, 2004.

      We transferred the Transocean Assets to Transocean primarily as in-kind dividends and transfers in exchange for the cancellation of debt to Transocean and, in some instances, for cash. Specified contracts were assigned to Transocean for no consideration. These transactions had no effect on our results of continuing operations except to the extent that debt was retired and any gain or loss was recognized.

      In February 2004, we 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 us and Transocean. 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.

      As part of the tax sharing agreement, we must pay Transocean for substantially all pre-closing income tax benefits utilized or deemed to have been utilized subsequent to the closing of the IPO. Accordingly, we recorded an equity transaction in 2004 to eliminate the valuation allowance associated with the pre-closing tax benefits and reflect the associated liability to Transocean for the pre-closing tax benefits as a corresponding obligation within the deferred income tax asset accounts. The net effect was a $181.4 million reduction in additional paid-in capital.

      In addition, Transocean agreed to indemnify us for certain tax liabilities that existed as of the IPO date which are currently estimated to be $10.3 million. We recorded the tax indemnification by Transocean as a credit to additional paid-in capital with a corresponding offset to a related party receivable from Transocean.

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:

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

      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 prospectus:

      Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those indicated. You 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 7A.                           Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

      The table below presents scheduled debt maturities and related weighted-average interest rates for each of the years ending December 31, relating to debt obligations as of December 31, 2004:

     At December 31, 2004, we had no variable rate debt outstanding and as such interest expense had no exposure to changes in interest rates. However, a large part of our cash investments would earn commensurately higher rates of return if interest rates increase. Using December 31, 2004 cash investment levels, a one percent increase in interest rates would result in approximately $0.7 million of additional interest income per year.

Foreign Exchange Risk

      Our international operations in Mexico, Trinidad and Venezuela expose us to foreign exchange risk. We use a variety of techniques to minimize the exposure to foreign exchange risk. Our primary foreign exchange risk management strategy involves structuring customer contracts to provide for payment in both U.S. dollars and local currency. The payment portion denominated in local currency is based on anticipated local currency requirements over the contract term. We may also use foreign exchange derivative instruments or spot purchases. We do not enter into derivative transactions for speculative purposes. At December 31, 2004, we did not have any outstanding foreign exchange contracts.

      In January 2003, Venezuela implemented foreign exchange controls that limited our ability to convert local currency into U.S. dollars and transfer excess funds out of Venezuela. Prior to August 2003, our drilling contracts in Venezuela typically called for payments to be made in local currency, even when the dayrate is

denominated in U.S. dollars. In August 2003, we negotiated an agreement with our principal customer in Venezuela to pay the majority of the U.S. dollar denominated amounts in U.S. dollars to one of our banks in the United States. The exchange controls could also result in an artificially high value being placed on the local currency.

      In the second quarter of 2003, we established a currency valuation allowance of $2.4 million pertaining to cash and receivables in Venezuela in order to adjust our Venezuelan financial assets to net realizable value as of June 30, 2003. This valuation allowance was deemed necessary due to the continuing political instability in Venezuela and the continuation of foreign exchange controls, which limit our ability to convert local currency into U.S. dollars and transfer excess funds out of Venezuela. In September 2004, we reversed $0.7 million of the currency valuation allowance that was no longer deemed necessary due to a sustained decrease in the net carrying value of assets denominated in the local currency in 2004, primarily as a result of an agreement with our primary customer in Venezuela to pay the majority of the U.S. dollar denominated accounts receivable in U.S. dollars to one of our banks in the United States. On March 3, 2005, Venezuela increased the official exchange rate from 1,920 bolivars/1 U.S. dollar to 2,150 bolivars/1 U.S. dollar. We do not anticipate that this change in exchange rate will have a material effect on our consolidated results of operations, financial condition or cash flows.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULE

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Stockholders and Board of Directors

TODCO

      We have audited the accompanying consolidated balance sheets of TODCO and Subsidiaries as of December 31, 2004 and 2003 and the related consolidated statements of operations, comprehensive loss, equity and cash flows for each of the three years in the period ended December 31, 2004. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

      We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of TODCO and Subsidiaries at December 31, 2004 and 2003, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

      As discussed in Note 2 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards (“SFAS”) 142 effective January 1, 2002, SFAS 123 effective January 1, 2003 and Financial Accounting Standards Board Interpretation No. 46 effective December 31, 2003.

Houston, Texas

February 11, 2005

TODCO AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS