Item 1.
Business
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 continue to benefit from any further increase in drilling activity associated with the search for natural gas in this region.
We operate a fleet of 64 drilling rigs consisting of 27 inland barge rigs, 24 jackup rigs, three submersible rigs, one platform rig, and nine land rigs. Currently, 48 of these rigs are located in shallow and inland waters of the United States with the remainder in Angola, Colombia, Mexico, Trinidad and Venezuela. We also operate a fleet of 49 inland tugs, 22 offshore tugs, 36 crew boats, 33 deck barges, 17 shale barges, five spud barges and two offshore barges.
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:
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U.S. Gulf of Mexico Segment - We currently have 18 jackup and three submersible rigs in the U.S. Gulf of Mexico shallow water market which begins at the outer limit of the transition zone and extends to water depths of about 350 feet. Our jackup rigs in this market consist of independent leg cantilever type units, mat-supported cantilever type rigs and mat-supported slot type jackup rigs that can operate in water depths up to 250 feet.
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U.S. Inland Barge Segment - Our barge rig fleet currently operating in this market consists of 12 conventional and 15 posted barge rigs. These units operate in marshes, rivers, lakes and shallow bay or coastal waterways that are known as the “transition zone.” This area along the U.S. Gulf Coast, where jackup rigs are unable to operate, is the world’s largest market for this type of equipment.
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Other International Segment - Our other operations are currently conducted in Angola, Colombia, Mexico, Trinidad and Venezuela. We operate one jackup rig in Angola and one in Colombia. In Mexico, we operate two jackup rigs and a platform rig. Additionally, we have two jackup rigs and one land rig in Trinidad and eight land rigs in Venezuela. We may pursue selected opportunities in other international areas from time to time.
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Delta Towing Segment - Delta Towing LLC (“Delta Towing”) operates a fleet of U.S. marine support vessels consisting primarily of shallow water tugs, crewboats and utility barges along the U.S. Gulf Coast and in the U.S. Gulf of Mexico.
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 Item 1A.
Item 1A.
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 primarily on the level of activity in the oil and gas industry in the U.S. Gulf Coast, which is significantly affected by often volatile oil and gas prices.
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:
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the demand for oil and gas in the United States and elsewhere,
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economic conditions in the United States and elsewhere,
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weather conditions in the United States and elsewhere,
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advances in exploration, development and production technology,
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the ability of the Organization of Petroleum Exporting Countries, commonly called “OPEC,” to set and maintain production levels and pricing,
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the level of production in non-OPEC countries,
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the policies of various governments regarding exploration and development of their oil and gas reserves, and
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the worldwide military and political environment, including uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or other crises in the Middle East or the geographic areas in which we operate or further acts of terrorism in the United States, or elsewhere.
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, and our results of operations may be volatile.
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.
Our industry is highly competitive, with intense price competition.
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.
The increase of supply of rigs in the Gulf of Mexico could create an excess supply of jackup rigs in the Gulf of Mexico and adversely affect utilization rates and dayrates for our rigs.
If, as a result of improved industry conditions in the Gulf of Mexico, inactive rigs that are currently not being marketed continue to be reactivated, jackup rigs or other mobile offshore drilling units are moved into the U.S. Gulf Coast from other regions or increased rig construction or rig upgrade programs by our competitors continue, a significant increase in the supply of jackups in the Gulf of Mexico could occur. Some of our competitors and speculators have ordered new jackup drilling rigs. We believe there are currently 51 jackup rigs on order with delivery dates ranging from 2006 to 2009. Most of the rigs on order are premium, cantilevered drilling units with
350 to 400 foot water depth capability. This trend of new jackup construction or other increases in the supply of jackup or other mobile offshore drilling units could curtail a further strengthening of utilization rates and dayrates, or reduce them.
Our ability to move our rigs to other regions is limited.
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. Nevertheless, the demand/supply balance for jackup and submersible rigs may vary somewhat from region to region. This is because the cost of a rig move is significant and there is limited availability of rig-moving vessels. Additionally, some rigs are designed to work in specific regions, in certain water depths or over certain types of seafloor conditions. 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.
Our jackup rigs are at a relative disadvantage to higher specification rigs.
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 business involves numerous operating hazards, and we are not fully insured against all of them.
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.
In October 2005, we renewed our principal insurance coverages for property damage, liability and occupational injury and illness for a one-year term. Our premium cost increased from approximately $8 million to approximately $15 million under these new policies, which also included an increase of approximately $340 million for insured values. Additionally, we reduced our insurance coverage to 70% of our losses over the applicable deductibles and we are uninsured with respect to the remaining 30% of such losses. We cannot predict what effect Hurricanes Katrina and Rita, or future storms, may have on our insurance costs. But we may again experience significant premium increases or we may be required to again reduce the percentage of our losses that would be covered by insurance.
If a significant accident or other event, including terrorist acts, war, civil disturbances, pollution or environmental damage, occurs that is not fully covered by insurance or a recoverable indemnity from a
customer, it could adversely affect our consolidated results of operation, financial position and cash flows. 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 subject to litigation.
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.
Failure to retain key personnel could hurt our operations.
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 rig increases, shortages of qualified personnel could arise, creating upward pressure on wages and difficulty in staffing rigs.
Loss of key management could hurt our operations.
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.
Unionization efforts could increase our costs or limit our flexibility.
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.
Governmental laws and regulations may add to our costs or limit drilling activity.
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.
Compliance with or a breach of environmental laws can be costly and could limit our operations.
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 consolidated results of operations, financial position or cash flows.
Our non-U.S. operations involve additional risks not associated with our U.S. operations.
We operate in regions that may expose us to political and other uncertainties, including risks of:
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terrorist acts, war and civil disturbances,
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expropriation or nationalization of equipment, and
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the inability to repatriate income or capital.
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 consolidated results of operations, financial position or cash flows.
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.
Our Venezuela operations are subject to adverse political and economic conditions.
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 Separation from Transocean
The terms of our separation from Transocean, the related agreements and other transactions with Transocean were determined in the context of a parent-subsidiary relationship and thus may be less favorable to us than the terms we could have obtained from an unaffiliated third party.
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:
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agreements related to the separation of our business from Transocean that provide for, among other things, the assumption by us of liabilities related to our business, the assumption by Transocean of liabilities
unrelated to our business, our respective rights, responsibilities and obligations with respect to taxes and tax benefits and the terms of our various interim and ongoing relationships, and
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the transfer to Transocean of assets that were not related to our business. See Note 20 to our consolidated financial statements included in Item 8 of this report.
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.
Our tax sharing agreement with Transocean could require substantial payments by us if an event occurs that accelerates the utilization or deemed utilization of pre-IPO tax benefits or an event could occur that may delay the utilization of the pre-IPO tax benefits.
In connection with the IPO, we entered into a tax sharing agreement with Transocean. Although we are currently disputing the enforceability of the agreement, we may be required to make substantial payments to Transocean, if we are unsuccessful in that dispute. For example, the agreement provides that we must pay Transocean for substantially all pre-IPO tax benefits utilized or deemed to have been utilized subsequent to the IPO. It also provides that we must pay Transocean for any tax benefit resulting from the delivery by Transocean of its stock to an employee of ours in connection with the exercise of an employee stock option and 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 the pre-IPO 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-IPO tax benefits. Our requirement to make this payment could have the effect of delaying or preventing a change of control. 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.
In September 2005, Transocean instructed us, pursuant to a provision in the tax sharing agreement, to take a tax deduction for profits realized by our current and former employees and directors from the exercise of Transocean stock options during calendar 2004. Transocean also indicated that it expected us to take a similar deduction in future years to the extent there were profits realized by our current and former employees and directors during those future periods.
It is our belief that the tax sharing agreement only requires us to pay Transocean for deductions related to stock option exercises by persons who were our employees on the date of exercise. Transocean disagrees with our interpretation of the tax sharing agreement as it relates to this issue and believes that we must pay Transocean for the tax benefit received for all stock option exercises, irrespective of whether any employment or other service provider relationship may have terminated prior to the exercise of the employee stock option. As such, Transocean initiated dispute resolution proceedings against us.
We recorded our obligation to Transocean based upon our interpretation of the tax sharing agreement. However, due to the uncertainty of the outcome of this dispute, we established a reserve equal to the benefit derived from stock option deductions relating to persons who were not our employees on the date of the exercise. For the tax year ending December 31, 2004, the deduction related to all of our current and former employees and directors was $8.8 million, with only $1.1 million attributable to persons who were our employees on the date of exercise. Additionally, we have been informed by Transocean that from January 1, 2005 to December 31, 2005, our current and former employees and directors have realized $85.3 million of gains from the exercise of Transocean stock options with $4.3 million relating to persons who were our employees on the date of exercise. If Transocean’s interpretation of the tax sharing agreement prevails, we would recognize a tax benefit for former employee and director stock option exercises and pay Transocean cash equal to 35% of the deduction we took. While this would not increase our tax expense, it would defer our utilization of pre-IPO income tax benefits.
As of December 31, 2005, we had approximately $282 million of estimated pre-IPO income tax benefits subject to the obligation to reimburse Transocean. If an acquisition of beneficial ownership had occurred on December 31, 2005, the estimated amount that we would have been required to pay Transocean would have been approximately $197 million, or 70% of the pre-IPO tax benefits at December 31, 2005.
The estimated liabilities to Transocean at December 31, 2005 and 2004 and the estimated amount of remaining pre-IPO tax benefits subject to the obligation to reimburse Transocean at December 31, 2005 do not reflect the benefit of the tax deduction for stock option exercises of former employees who were not our employees on the date of the exercise and are presented within “accrued income taxes - related party” in the Company’s condensed consolidated balance sheets.
Furthermore, even though Transocean no longer owns any shares of our common stock, the agreement provides that 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-IPO tax benefits. See Note 12 to our consolidated financial statements for the period ended December 31, 2005 included in Item 8 of this report.
The 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-IPO 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.
Our tax sharing agreement with Transocean could delay or preclude us from realizing post-IPO tax benefits.
The tax sharing agreement with Transocean provides that if the utilization of a pre-IPO tax benefit defers or precludes our utilization of any post-IPO tax benefit, our payment obligation with respect to the pre-IPO tax benefit generally will be deferred until we actually utilize that post-IPO tax benefit. This payment deferral will not apply with respect to, and we will have to pay currently for the utilization of pre-IPO tax benefits to the extent of (a) up to 20% of any deferred or precluded post-IPO tax benefit arising out of our payment of foreign income taxes, and (b) 100% of any deferred or precluded post-IPO tax benefit arising out of a carryback from a subsequent year. Therefore, we may not realize the full economic value of tax deductions, credits and other tax benefits that arise post-IPO until we have utilized all of the pre-IPO tax benefits, if ever.
Other Risks
We could incur substantial losses during industry downturns and may need additional financing to withstand industry downturns.
Although we recognized net income of $59.4 million for the year ended December 31, 2005, our net losses from continuing operations before cumulative effect of a change in accounting principle were approximately $29 million and $222 million during the years ended December 31, 2004 and 2003, respectively, and we could incur 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, so stockholders may not receive funds without selling their common stock.
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. In 2005, due to favorable market conditions, our unrestricted cash balances grew to levels that exceeded our foreseeable needs for cash held for reinvestment and unknown contingencies. We secured the approval of our lenders and our board of directors declared a special cash dividend of $1.00 per share that was paid in 2005. This special cash dividend is not indicative of a change in our basic dividend policy nor does it guarantee that any future dividends will be paid. 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 rights agreement and provisions in our charter documents may inhibit a takeover, which could adversely affect the value of our Class A common stock.
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:
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classification of the members of our board of directors into three classes, with each class serving a staggered three-year term,
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requiring our stockholders to give advance notice of their intent to make nominations for the election of directors or to submit a proposal at an annual meeting of the stockholders,
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limitations on the ability of our stockholders to amend specified provisions of our amended and restated certificate of incorporation and bylaws,
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the denial of any right of our stockholders to act by unanimous written consent in lieu of a meeting,
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the denial of any right of our stockholders to remove members of our board of directors except for cause, and
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the denial of any right of our stockholders to call special meetings of the stockholders.
We are also party to a rights agreement that could delay or prevent a change of control that a stockholder might consider favorable.
Item 1B.
Item 1B.
Unresolved Staff Comments
None.
Item 2.
Item 2.
Properties
We maintain our principal executive offices in Houston, Texas and have operational offices in Houma, Louisiana; Maturin, Venezuela; La Romaine, Trinidad; Luanda, Angola; Santa Marta, Colombia; Bogota, Colombia; and Ciudad del Carmen, Mexico. We also have warehouse and yard facilities in Houma, Louisiana, La Romaine, Trinidad and Maturin, Venezuela. We lease all of these facilities, except for the warehouse and yard facilities in Maturin.
Item 3.
Item 3.
Legal Proceedings
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.
TODCO vs. Transocean Inc. and Transocean Holdings Inc. (“Transocean”). In connection with our separation from Transocean, we executed a tax sharing agreement with Transocean. The agreement provides that we must pay Transocean for certain pre-IPO tax benefits utilized or deemed to have been utilized subsequent to the IPO. The agreement also provides that we must pay Transocean for any tax benefit resulting from the delivery by Transocean of its stock to an employee of our tax group that results in a tax benefit to us. In September 2005, Transocean instructed us to take a tax deduction for profits realized by our current and former employees and directors from the exercise of Transocean stock options during calendar 2004. Transocean also indicated that it expected us to take a similar deduction in future years to the extent there were profits realized by our current and former employees and directors during those future periods. We believe that the applicable provision of the agreement only requires us to pay Transocean for deductions related to stock option exercises by persons who were employees of our tax group on the date of exercise and we have advised Transocean accordingly. Both parties have issued arbitration demand notices to the other and are in the process of attempting to select a neutral arbitrator to decide the dispute. In addition, we have filed a lawsuit against Transocean in Texas State District Court seeking to have the agreement overturned in its entirety. The dispute is in the early stages of development and it is difficult to predict the eventual outcome. In any event, we do not expect the outcome of this matter to have a material adverse effect on our consolidated results of operations, financial position or cash flows.
Robert E. Aaron et al. vs. Phillips 66 Company et al. Circuit Court, Second Judicial District, Jones County, Mississippi. This is the case name used to refer to several cases that have been filed in the Circuit Courts of the State of Mississippi involving 768 persons that allege personal injury arising out of asbestos exposure in the course of their employment by the defendants between 1965 and 2002. The complaints name as defendants, among others, certain of our subsidiaries and 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 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. The trial court granted 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 served. In that regard, a majority of these cases have been assigned to a special master who has approved a form of questionnaire to be completed by plaintiffs so that claims made may be properly served against specific defendants. As of the date of this report, approximately 699 questionnaires had been submitted. Of those, approximately 103 shared periods of employment by us and Transocean which could lead to claims against either company. We have not determined which entity would be responsible for such claims under the master separation agreement between the two companies. We have not yet had an opportunity to conduct any additional discovery to verify 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 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.
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 two 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 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. The case has now been dismissed.
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.
Item 4.
Item 4.
Submission of Matters to a Vote of Security Holders
None during the fourth quarter of 2005.
PART II
Item 5.
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
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 June 10, 2005 that he was not aware of any violation by TODCO of NYSE corporate governance listing standards as of that date.
As of February 21, 2006, there were approximately 390 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 February 21, 2006, the last reported sales price of our Class A common stock was $37.20 per share.
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. Subject to Delaware law, 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. However, due to favorable market conditions, our unrestricted cash balances grew to levels that exceeded our foreseeable needs for cash held for reinvestment and unknown contingencies. After we secured the approval of our lenders, our board of directors declared a special cash dividend of $1.00 per share, totaling $61.2 million, that was paid in August 2005. This special cash dividend is not indicative of a change in our basic dividend policy nor does it guarantee that any future dividends will be paid. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Sources of Liquidity and Capital Expenditures.”
Item 6.
Item 6.
Selected Financial Data
The following table sets forth selected financial information for our company. The financial information for the years ended December 31, 2005, 2004 and 2003, and as of December 31, 2005 and 2004, has been derived from our audited financial statements included elsewhere in this report. The financial information for the year ended December 31, 2002, the one month ended January 31, 2001 and the eleven months ended December 31, 2001, and as of December 31, 2003, 2002 and 2001 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.
(a)
Included in the one month ended January 31, 2001 are $58.1 million of merger related expenses and a $64.0 million impairment loss on long-lived assets related to the disposal of the marine support vessel business.
(b)
Included in the eleven months ended December 31, 2001 are a $1.1 million impairment loss on long-lived assets and a $27.5 million loss on retirement of debt.
(c)
Included in 2002 are a $17.5 million impairment loss on long-lived assets, a $381.9 million goodwill impairment and a $18.8 million loss on retirement of debt.
(d)
Included in 2003 are an $11.3 million impairment loss on long-lived assets, a $21.3 million impairment loss on a note receivable from an unconsolidated joint venture and a $79.5 million loss on retirement of debt.
(e)
Included in 2004 are a $2.8 million impairment loss on long-lived assets and a $1.9 million loss on retirement of debt.
(f)
Includes current portion.
(g)
Our consolidated results of operations for the years ended December 31, 2005 and December 31, 2004 reflect the consolidation of our ownership interest in Delta Towing effective December 31, 2003 in accordance with Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51 (“FIN 46”). Accordingly, our results for 2004 and 2005 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.
Item 7.
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:
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U.S. Gulf of Mexico Segment - We currently operate 18 jackup and three submersible rigs in the U.S. Gulf of Mexico shallow water market which begins at the outer limit of the transition zone and extends to water depths of about 350 feet. Our jackup rigs in this market consist of independent leg cantilever type units, mat-supported cantilever type rigs and mat-supported slot type jackup rigs that can operate in water depths up to 250 feet.
•
U.S. Inland Barge Segment - Our barge rig fleet currently operating in this market consists of 12 conventional and 15 posted barge rigs. These units operate in marshes, rivers, lakes and shallow bay or coastal waterways that are known as the “transition zone”. This area along the U.S. Gulf Coast, where jackup rigs are unable to operate, is the world’s largest market for this type of equipment.
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Other International Segment - Our other operations are currently conducted in Angola, Colombia, Mexico, Trinidad and Venezuela. We operate one jackup rig in Angola and one jackup rig in Colombia. In Mexico, we operate two jackup rigs and a platform rig. We have two jackup rigs and a land rig in Trinidad and eight land rigs in Venezuela. We may pursue selected opportunities in other international areas from time to time.
•
Delta Towing Segment - During 2005, we had a 25% interest in Delta Towing, a joint venture that operates a fleet of U.S. marine support vessels consisting primarily of shallow water tugs, crewboats and utility barges. In January 2006, we purchased the 75% interest owned by Chouest. See Notes 4 and 21 to our consolidated financial statements included in Item 8 of this report.
Our operating revenues for our drilling segments are based on dayrates received for our drilling services and the number of operating days during the relevant periods. The level of our operating revenues depends on dayrates, which in turn are primarily a function of industry supply and demand for drilling units in the market segments in which we operate. Supply and demand for drilling units in the U.S. Gulf Coast, which is our primary operating region, has historically been volatile. During periods of high demand, our rigs typically achieve higher utilization and dayrates than during periods of low demand.
Our operating and maintenance costs for our drilling segments represent all direct and indirect costs associated with the operation and maintenance of our drilling rigs. The principal elements of these costs are direct and indirect labor and benefits, freight costs, repair and maintenance, insurance, general taxes and licenses, boat and helicopter rentals, communications, tool rentals and services. Labor, repair and maintenance and insurance costs represent the most significant components of our operating and maintenance costs.
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 in our industry that could effect our operations, including:
•
High Natural Gas Prices. While U.S. natural gas prices are volatile, the rolling twelve-month average price of natural gas has increased from $2.11 in January 1994 to $9.10 in January 2006. High natural gas prices in the United States have resulted in more exploration and development drilling activity and higher utilization and dayrates for drilling companies like us. If high natural gas prices are sustained, we expect this trend to continue.
•
Need for Increased Natural Gas Drilling Activity. From 1994 to 2004, U.S. demand for natural gas grew at an annual rate of 0.7% while its supply grew at an annual rate of 0.2%. We believe that this supply and demand growth imbalance will continue if demand for natural gas continues to increase and production decline rates continue to accelerate. Even though the number of U.S. gas wells drilled has increased overall in recent years, a corresponding increase in production has not been realized. We believe that an increase in U.S. drilling activity will be required for the natural gas industry to meet the expected increased demand for, and compensate for the slowing production of, natural gas in the United States.
•
Trend Towards Drilling Deeper Shallow Water Gas Wells. A current trend by oil and gas companies is to drill deep gas wells along the U.S. Gulf Coast in search of new and potentially prolific untapped natural gas reserves. We believe that this trend towards deeper drilling will benefit premium jackup rigs as well as barge rigs and submersible rigs that are capable of drilling deep gas wells. In addition, this trend will indirectly
benefit conventional jackup fleets, such as ours, as the use of premium rigs in the U.S. Gulf Coast to drill deep wells should reduce the supply of rigs available to drill shallower wells.
•
Redeployment of Jackup Rigs. Greater demand for jackup rigs in international areas over the last three years has reduced the overall supply of jackups in the U.S. Gulf of Mexico. This has created a more favorable supply environment for the remaining jackups, including ours. This favorable supply environment has contributed to increased jackup utilization and dayrates.
•
New Building of Jackup Rigs. In response to the improved market conditions, our competitors and speculators have recently begun ordering new jackup drilling rigs. We believe there are currently 51 jackup rigs on order with delivery dates ranging from 2006 to 2009. Most of the rigs on order are premium cantilevered drilling units with 350 to 400 foot water depth capability. This trend of new jackup construction could curtail a further strengthening of utilization and dayrates, or reduce them. However, the worldwide jackup fleet is aging and will need to be replaced at some point. Currently, the average age worldwide is approximately 24 years old. In addition, attrition continues and was recently accelerated when the U.S. Gulf of Mexico experienced two major hurricanes, which destroyed or significantly damaged nine jackup drilling rigs.
Market conditions for our U.S. Gulf Coast jackup fleet improved beginning in the third quarter of 2003 and continued to improve through 2005. As shown in the following table, from the fourth quarter of 2004 through the fourth quarter of 2005, our average revenue per day for U.S. Gulf of Mexico jackups and submersibles improved by 52%. During the same period, average revenue per day for our U.S. inland barges improved by 34%. As of February 20, 2006, 11 of our 16 marketed jackup and submersible rigs working in the U.S. Gulf Coast were operating at dayrates ranging from $55,000 to $105,300. As of February 20, 2006, 16 of our 17 marketed inland barges were operating at dayrates ranging from $20,400 to $41,700. We anticipate that the declining jackup rig supply in the U.S. Gulf Coast due to the recent hurricane damage, the redeployment of rigs to international locations and the trend towards more deep gas well drilling will continue to result in improved utilization and higher dayrates into 2006. As a result, we are actively pursuing long-term contracts with our customers to reactivate our five cold stacked U.S. Gulf of Mexico jackup rigs. Additionally, we are pursuing long-term contracts to reactivate some of our ten cold stacked inland barge rigs.
The following table shows our average rig revenue per day and utilization for the quarterly periods ended on or prior to December 31, 2005 with respect to each of our three drilling segments. Average rig revenue per day is defined as operating revenue earned per revenue earning day in the period. Utilization in the table below is defined as the total actual number of revenue earning days in the period as a percentage of the total number of calendar days in the period for all drilling rigs in our fleet, as adjusted to include calendar days available for rigs that were held for sale during the periods ended on or prior to December 31, 2003.
In response to strengthening demand for drilling rigs, we began reactivating certain of our cold stacked rigs beginning in the second quarter of 2005 and continuing into 2006. We did so, however, only if we first obtained a term drilling contract for each reactivated rig at a dayrate sufficient to recover, over the full term of the contract, all
of our expected operating expenses of performing the contract plus all, or a substantial portion of, our anticipated costs of reactivating the rig.
Since December 31, 2004, we have commenced or completed the reactivation of eight drilling rigs, consisting of three jackup rigs, two submersible rigs and three barge rigs. We estimate that the total actual and estimated remaining costs of reactivating these eight rigs will be approximately $82 million but that we will receive $178 million in total historical and estimated future revenues over the full term of the related drilling contracts. For additional information concerning each of our completed and pending rig reactivations and the related term contract, please see “Business - Reactivation of Rigs Against Term Contracts.” Approximately $5.0 million was capitalized and $12.2 million was charged to operating and maintenance expense in connection with rig reactivations in 2005. With respect to currently pending rig reactivations, we estimate that $22.3 million of reactivation costs will be capitalized in 2006, and that approximately $42.2 million will be charged to operating and maintenance expense.
We expect that we may reactivate or commit to reactivate additional cold stacked rigs in 2006, but only if we are able to obtain suitable term contracts on the reactivated rig or if we are confident that we will be able to do so in view of then favorable market conditions. In anticipation of reactivating cold stacked rigs in 2006, we have ordered certain rig components and equipment that have extended delivery times. See “- Liquidity and Capital Resources - Sources of Liquidity and Capital Resources,” below.
In the third quarter of 2003, we were awarded contracts with PEMEX for two of our jackup rigs and a platform rig. After upgrades to comply with contract specifications, one rig, THE 206, began operating on a 720-day contract in early November 2003 at a contract dayrate of approximately $42,000. A new 615-day contract was awarded for THE 206 at dayrates of approximately $64,000 which became effective in late October 2005. The other jackup rig, THE 205, 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.
All of the damage caused by these two hurricanes is covered under our hull and machinery insurance policy with a total incident deductible of $1.0 million, which will be exceeded in both incidents. Currently, we have recognized $0.8 million of insurance claims expense through the fourth quarter of 2005 for the insurance deductibles related to the damage sustained during Hurricane Katrina. We also incurred $2.6 million in expenses related to damages caused by Hurricane Rita. We recorded $1.6 million of claims receivable for the repair amount incurred above the $1.0 million insurance deductible related to losses sustained during Hurricane Rita. Any remaining expenses incurred related to damage caused by Hurricane Rita will be recorded as a claims receivable.
In January 2005, we retained Simmons & Company International to explore alternatives for the disposition of our Venezuelan land drilling business, which is not viewed by us as being core to our ongoing offshore drilling business. The evaluation may result in the sale of some or all of our Venezuelan assets.
In October 2005, we renewed our principal insurance coverages for property damage, liability and occupational injury and illness for a one-year term. Generally, our deductible levels under the new hull and machinery policies are 15% of individual insured asset values per occurrence except in the event of a total loss only where the deductible would be zero. An annual limit of $75.0 million and a minimum deductible of $5.0 million per occurrence applies in the event of a windstorm. Previously, our deductible level under these policies was $1.0 million per occurrence with no windstorm limits. In addition, in an effort to control premium costs, we reduced our insurance coverage to 70% of our losses in excess of the applicable deductible and we are uninsured for the remaining 30% of any such losses. The primary marine package also provides coverage for cargo, control of well, seepage, pollution and property in our care, custody and control. Our deductible for this coverage varies between $250,000 and $1.0 million per occurrence depending upon the coverage line. 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 $1.0 million deductibles per occurrence. We also have an excess liability policy that extends our coverage to an aggregate of $200.0 million under all of these policies. Our insurance program also includes separate policies that cover certain liabilities in foreign countries where we operate.
Our premium cost increased from approximately $8 million to approximately $15 million under these new policies, which also included an increase of approximately $340 million for insured values. We believe our current insurance coverage, deductibles and the level of risk involved is adequate and reasonable. However, insurance premiums and/or deductibles could be increased or coverages may be unavailable in the future.
IPO and Separation from Transocean
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 our initial public offering in which Transocean sold 13,800,000 shares of our Class A common stock (the “IPO”). After several stock offerings and a private sale in 2004 and 2005, Transocean had converted all of its unsold shares of Class B common stock into an equal number of shares of Class A common stock and had sold all of its remaining shares of our common stock. As a result of the conversion, no Class B common stock was outstanding as of December 31, 2005 and 2004. We received no proceeds from any of these sales.
Prior to the IPO, we entered into several agreements with Transocean defining the terms of the separation of our business from Transocean’s business. These agreements included a Master Separation Agreement which defined our separate 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. See Notes 1, 3, 6, 12 and 20 in the accompanying Notes to Consolidated Financial Statements included in Item 8 of this report for further discussion concerning 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 “2004 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 2004 from the 2004 Plan which has since been replaced by a new plan. In 2005, a new plan was adopted to continue to provide employees, non-employee directors and our consultants with additional incentives and increase their personal stake in our success (the “2005 Plan”). Based upon the price per share at date of issuance, the value of the 2005 Plan and the 2004 Plan awards that we will recognize as compensation expense is approximately $24.4 million. During 2005 and 2004 we recognized $7.6 million and $10.6 million, respectively, of compensation expense related to these awards and grants. We
will amortize the remaining $6.2 million to compensation expense over the vesting period of the awards and options. In addition to these grants under the 2005 Plan and the 2004 Plan, we expect to make additional grants of restricted stock, deferred performance units, deferred stock units and stock options annually. The value of any additional awards under the 2005 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 “- Variable Interest Entity - Delta Towing”), 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 included 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. During 2005, the face value of our senior notes payable was further reduced to approximately $16 million. Our debt levels and, correspondingly, our interest expense were substantially lower in 2005 and 2004 compared to prior years as a result of the notes payable to Transocean prior to the IPO.
In connection with the IPO, we entered into a tax sharing agreement with Transocean. The agreement provides that we must pay Transocean for substantially all pre-IPO tax benefits utilized or deemed to have been utilized subsequent to the closing of the IPO. It also provides that we must pay Transocean for any tax benefit resulting from the delivery by Transocean of its stock to one of our active employees in connection with the exercise of an employee stock option. In return, Transocean agreed to indemnify us against substantially all pre-IPO income tax liabilities.
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 the pre-IPO 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-IPO tax benefits.
Under the tax sharing agreement with Transocean, if the utilization of a pre-IPO tax benefit defers or precludes our utilization of any post-IPO tax benefit, our payment obligation with respect to the pre-IPO tax benefit generally will be deferred until we actually utilize that post-IPO tax benefit. This payment deferral will not apply with respect to, and we will have to pay currently for the utilization of pre-IPO tax benefits to the extent of (a) up to 20% of any deferred or precluded post-IPO tax benefit arising out of our payment of foreign income taxes, and (b) 100% of any deferred or precluded post-IPO tax benefit arising out of a carryback from a subsequent year. Therefore, we may not realize the full economic value of tax deductions, credits and other tax benefits that arise post-IPO until we have utilized all of the pre-IPO tax benefits, if ever.
Upon consummation of the IPO, we recorded the tax sharing agreement to eliminate the valuation allowance associated with the pre-IPO tax benefits and reflect the associated liability to Transocean for the pre-IPO tax benefits as a corresponding obligation within the deferred income tax accounts. The net effect was a $181.4 million reduction in additional paid-in capital. In addition, we recorded as a credit to additional paid-in capital $10.3 million for Transocean’s indemnification for pre-IPO liabilities that existed as of the IPO date with a corresponding offset to a related party receivable from Transocean.
During the first quarter of 2005, we recorded an additional $7.7 million in pre-IPO deferred state tax liabilities that existed at the IPO date. The recognition of these pre-IPO deferred state tax liabilities resulted in a $7.7 million reduction in additional paid-in capital, $0.9 million of deferred state tax benefit and a $6.8 million increase in deferred tax liabilities.
In September 2005, Transocean instructed us, pursuant to a provision in the tax sharing agreement, to take a tax deduction for profits realized by our current and former employees and directors from the exercise of Transocean stock options during calendar 2004. Transocean also indicated that it expected us to take a similar deduction in future years to the extent there were profits realized by our current and former employees and directors during those future periods.
It is our belief that the tax sharing agreement only requires us to pay Transocean for deductions related to stock option exercises by persons who were our employees on the date of exercise. Transocean disagrees with our interpretation of the tax sharing agreement as it relates to this issue and believes that we must pay for all stock option exercises, irrespective of whether any employment or other service provider relationship may have terminated prior to the exercise of the employee stock option. As such, Transocean initiated dispute resolution proceedings against us.
We recorded our obligation to Transocean based upon our interpretation of the tax sharing agreement. However, due to the uncertainty of the outcome of this dispute, we established a reserve equal to the benefit derived from stock option deductions relating to persons who were not our employees on the date of the exercise. For the tax year ending December 31, 2004, the deduction related to all of our current and former employees and directors was $8.8 million, with only $1.1 million attributable to persons who were our employees on the date of exercise. Additionally, we have been informed by Transocean that from January 1, 2005 to December 31, 2005, our current and former employees and directors have realized $85.3 million of gains from the exercise of Transocean stock options with $4.3 million relating to persons who were our employees on the date of exercise. If Transocean’s interpretation of the tax sharing agreement prevails, we would recognize a tax benefit for former employee and director stock option exercises and pay Transocean in cash for an amount equal to 35% for the deduction. While this would not increase our tax expense, it would defer utilization of pre-IPO income tax benefits.
During the years ended December 31, 2005 and 2004, we utilized pre-IPO income tax benefits to offset our current federal income tax obligation resulting in a liability to Transocean of $43.8 million and $7.6 million, respectively. Additionally, during the years ended December 31, 2005 and 2004, we utilized pre-IPO state tax benefits resulting in a liability to Transocean of $0.1 million and $0.8 million, respectively. We also utilized pre-IPO foreign tax benefits during 2005 resulting in a liability to Transocean of $1.0 million at December 31, 2005. There was no liability due to Transocean for the utilization of foreign tax benefits at December 31, 2004. As of December 31, 2005 and 2004, we estimate our liability to Transocean to be $44.9 million and $8.4 million, respectively, for pre-IPO federal, state and foreign income tax benefits utilized.
As of December 31, 2005, we had approximately $282 million of estimated pre-IPO income tax benefits subject to the obligation to reimburse Transocean. If an acquisition of beneficial ownership had occurred on December 31, 2005, the estimated amount that we would have been required to pay Transocean would have been approximately $197 million, or 70% of the pre-IPO tax benefits at December 31, 2005.
The estimated liabilities to Transocean at December 31, 2005 and 2004 and the estimated amount of remaining pre-IPO income tax benefits subject to the obligation to reimburse Transocean at December 31, 2005 do not reflect the benefit of the tax deduction for stock option exercises of former employees who were not our employees on the date of the exercise and are presented within “accrued income taxes - related party” in our condensed consolidated balance sheets.
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 59% of our total assets as of December 31, 2005. 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:
(a)
Available days are the total number of calendar days in the period for all drilling rigs in our fleet.
(b)
Utilization is the total number of operating days in the period as a percentage of the total number of calendar days in the period for all drilling rigs in our fleet.
(c)
Average rig revenue per day is defined as revenue earned per operating day for the applicable segment, and as total U.S. Gulf of Mexico, U.S. Inland Barge and Other International revenues per rig operating days for “Total Company.”
(d)
Excludes depreciation, amortization and general and administrative expenses.
Our consolidated results of operations for the years ended December 31, 2005 and December 31, 2004 reflect the consolidation of our 25% ownership interest in Delta Towing effective December 31, 2003 in accordance with FIN 46. Accordingly, our results for 2005 and 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 “- Variable Interest Entity - Delta Towing” for a discussion of the effects of FIN 46 on our investment in Delta Towing.
Years Ended December 31, 2005 and 2004
Operating Revenues. Total operating revenues increased $182.8 million, or 52%, during 2005 as compared to 2004, primarily due to higher overall average rig revenue per day earned in 2005, as compared to 2004. Overall average rig revenue per day increased from $29,100 for 2004 to $38,200 for 2005, as a consequence of the continued improvement of market conditions in the U.S. Gulf of Mexico and transition zone along the U.S. Gulf Coast, the revenue contribution from our platform rig which began operating in Mexico in December 2004, the commencement of operations in Angola and three land rigs which began operating in Venezuela in the last half of 2004. Average rig utilization of 54% for 2005 was up from 43% in 2004.
Operating revenues for our U.S. Gulf of Mexico segment increased $95.5 million, or 68%, in 2005, as compared to 2004. In 2005, we achieved higher average rig revenue per day for our jackup and submersible drilling fleet, improving from $34,200 per day to $53,000 per day. This resulted in an additional $80.1 million in operating
revenues for 2005, as compared to the same period in 2004. The increase in average rig revenue per day is the result of our success in obtaining contracts with our customers at higher dayrates in response to increased market demand. Results for 2005 also reflect higher utilization for our current rig fleet in this market, after giving effect to the transfer of the jackup drilling unit THE 156 from our Other International segment in the fourth quarter of 2004. This increase in utilization resulted in $4.6 million in additional rig revenues in 2005, as compared to the same period in 2004. The transfer of THE 156 generated operating revenues of $10.8 million in 2005 before it was transferred to Colombia in the last quarter of 2005.
Operating revenues for our U.S. Inland Barge segment increased $40.2 million, or 38%, in 2005, as compared to the same period in the prior year, primarily due to higher average rig revenue per day achieved in 2005, as compared to 2004. Average rig revenue per day increased from $22,200 for 2004 to $28,400 for 2005, as a result of our successful marketing efforts in negotiating higher dayrates for our fleet of inland barges during 2005. The increase in average rig revenue per day resulted in additional revenues of $31.7 million for 2005 as compared to 2004. Utilization of our inland barge fleet was 51% for 2005, as compared to 43% for 2004, which resulted in $8.5 million additional operating revenues in 2005 as compared to 2004.
Operating revenues for our Other International segment were $101.8 million for 2005. The 39%, or $28.5 million, increase over operating revenues reported for 2004 reflects commencement of operation of our platform rig in Mexico in late 2004 under a long-term contract, the commencement of operations in Angola in September 2005 and the commencement of operations in Venezuela of three land rigs in the last half of 2004. The operation of the platform rig contributed an additional $12.7 million in operating revenues during 2005. Higher land rig utilization in Venezuela contributed an additional $16.7 million in operating revenues in 2005 compared to 2004. In addition, the commencement of operations in Angola in September 2005 contributed an additional $8.1 million to 2005 operating revenues. Also, THE 156 was transferred from the U.S. Gulf of Mexico to Colombia in the last quarter of 2005 and generated $0.7 million revenue after beginning operations in December. These favorable contributions were offset by the transfer of THE 156 from Venezuela to the U.S. Gulf of Mexico which generated $15.6 million in operating revenues for 2004.
Our operating revenues for 2005 included $49.6 million related to the operation of Delta Towing’s fleet of U.S. marine support vessels which increased from $31.0 million recognized in 2004 due to increased vessel utilization in response to improved market conditions.
Operating and Maintenance Expenses. Total operating and maintenance expenses increased $63.5 million, or 24%, in 2005 as compared to operating expenses of $259.7 million for 2004.
Operating and maintenance expenses for our U.S. Gulf of Mexico segment were $23.0 million higher for 2005 as compared to 2004. The factors contributing to this 25% increase were additional personnel costs of $6.4 million relating to the higher utilizations and wage increases in 2005, the relocation of THE 156 back to the U.S. Gulf of Mexico ($4.7 million) and increased mobilization expense ($0.7 million). Repair and maintenance expense resulting from the higher utilizations increased $6.0 million for 2005 as compared to 2004. Our insurance claims expense increased $3.8 million from damages sustained during Hurricanes Katrina and Rita and also from damage to THE 202 during a jacking incident. Our 2004 expenses were also favorably impacted by a $0.5 million reduction in our reserve for uncollectible accounts receivable and a $0.7 million recovery of insurance claims related to one of our jackup drilling rigs.
Operating and maintenance expenses for our U.S. Inland Barge segment were $94.1 million for 2005 as compared to $82.6 million for 2004. This $11.5 million, or 14%, increase was primarily the result of increasing personnel costs ($8.6 million) and higher repair and maintenance expenses ($3.1 million), primarily on Rig 64 hull repairs and the reactivation of Rig 28, which was cold stacked and began operations in the third quarter of 2005. Mobilization expense and rental recharges increased $1.1 million when comparing results from 2005 to 2004 as a result of increased activity and utilization. Insurance claims expense related to hurricane damage in 2005 of $0.6 million was more than offset by a $1.1 million decrease in personal injury claim expense and insurance costs when comparing 2005 to 2004, primarily the result of an improvement in the actuarial factors used to develop our personal injury claims.
Operating and maintenance expenses for our Other International segment for 2005 increased $24.8 million, or 40%, as compared to 2004. This increase was due to our platform rig in Mexico which began operations in December 2004 and incurred $8.7 million of expenses in 2005, an increase of $5.8 million over 2004. In addition, we incurred higher expenses on our other Mexico operations of $1.7 million during 2005 as compared to 2004. Higher land rig utilization and increasing costs in Venezuela resulted in an increase of $11.5 million when comparing 2005 to 2004. Reactivation of THE 185 for operations in Angola resulted in an additional $12.6 million in expense being incurred during 2005. The commencement of operations of a land rig in Trinidad in the last quarter of 2005 contributed an additional $1.7 million in expenses. The relocation of THE 156 from the U.S. Gulf of Mexico segment to Colombia in the last quarter of 2005 contributed an additional $0.6 million in operating expenses. These additional expenses were partially offset by the transfer of THE 156 from Venezuela in the last quarter of 2004 to our U.S. Gulf of Mexico operations which lowered expenses in our Other International segment by $10.4 million for 2005 as compared to 2004 and a $0.8 million reduction in a Venezuelan labor claim legal reserve due to favorable settlements.
Delta Towing operations incurred $25.7 million in operating costs for 2005. This represented a $4.2 million, or 20%, increase over operating costs of $21.5 million recognized in 2004 which was principally due to increased marine support vessel utilization and increased repairs and maintenance expenses.
General and Administrative Expenses. General and administrative expenses were $37.7 million for 2005 as compared to $34.0 million for 2004. General and administrative expenses for 2005 increased $3.7 million as compared to 2004, due primarily to higher payroll costs of $3.8 million and an increase in Delta Towing and other general and administrative expenses of $1.9 million. Additional audit fees, a secondary offering in May 2005 and Sarbanes-Oxley compliance work contributed to an increase of $2.9 million in our professional, legal and accounting fees. These increases were offset by a decrease in stock option and restricted stock award expense of $4.5 million. The stock option expense of $12.1 million recognized in 2004 included $10.6 million of stock compensation expense associated with post-IPO grants of stock options and restricted stock awards. Comparable stock compensation expense for 2005 was $7.6 million which also included expense related to deferred performance units and deferred stock units. Additionally in 2004, we recognized a one-time $1.5 million stock compensation expense related to the modification of Transocean stock options held by some of our employees. In addition, we incurred no administrative charges under our transition services agreement with Transocean in 2005 as compared to $0.4 million in 2004.
Gain on Disposal of Assets, Net. During 2005, we realized net gains on disposal of assets of $25.1 million related to the sale of three out-of-service jackup rigs, THE 154 ($9.3 million), THE 151 ($6.7 million) and THE 192 ($3.8 million), the sale of drill pipe and miscellaneous equipment ($4.1 million) and the sale of five marine support vessels by Delta Towing ($1.2 million). 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 the sale of drill pipe and miscellaneous equipment ($2.1 million).
Interest Expense. Third party interest expense and interest expense-related party decreased $3.7 million in 2005 as compared to 2004, primarily due to lower debt balances owed to third parties and Transocean. In the first quarter of 2004, we completed the debt-for-equity exchange of all our remaining outstanding related party debt payable to Transocean and in the second quarter of 2005 we made payments of $7.7 million to retire our 6.75% Senior Notes.
Income Tax Expense (Benefit). The income tax expense of $44.5 million for 2005 reflects a 42.8% effective tax rate (“ETR”) and is comprised of our obligation to Transocean under the tax sharing agreement for the utilization of pre-IPO federal and state tax benefits and the recognition of foreign deferred tax liabilities in certain foreign tax jurisdictions where we have a low tax basis in our assets. The ETR is higher than the federal rate of 35% principally due to foreign tax expense, state tax expense and a 2004 tax return adjustment. Tax expense for 2005 also includes the effect of recognizing an additional $7.7 million in pre-IPO deferred state tax liabilities that existed at the IPO date. The recognition of these pre-IPO deferred state tax liabilities resulted in a $7.7 million reduction in additional paid-in capital, $0.9 million of deferred state tax benefit and a $6.8 million increase in deferred tax liabilities.
Under the tax sharing agreement, we are unable to reduce our federal tax benefit obligation owed to Transocean for the state tax benefits utilized. For 2004, our net loss generated a tax benefit of $12.5 million, or a 30.2% ETR, which was lower than the federal tax rate due to a valuation allowance on the Delta Towing tax benefits generated during 2004.
During 2005, Transocean instructed us, pursuant to a provision in the tax sharing agreement, to take a tax deduction for profits realized by current and former employees and directors who exercised Transocean stock options during calendar 2004. Transocean also indicated that it expected us to take a similar deduction in future years to the extent there were profits realized by our current and former employees and directors during those future periods.
It is our belief that the tax sharing agreement only requires us to pay Transocean for deductions related to stock option exercises by persons who were our employees on the date of exercise. The payment obligation is generally 35% of the tax deduction. Transocean disagrees with our interpretation of the tax sharing agreement as it relates to this issue and it believes that we must pay for all stock option exercises, irrespective of whether any employment or other service provider relationship may have terminated prior to the exercise of the employee stock option. As such, Transocean initiated dispute resolution proceedings against us.
We recorded our obligation to Transocean based on our interpretation of the tax sharing agreement. However, due to the uncertainty of the outcome of this dispute, we established a reserve equal to the benefit derived from stock option deductions relating to persons who were not our employees on the date of the exercise. For the tax year ending December 31, 2004, the deduction related to all of our current and former employees and directors was $8.8 million with only $1.1 million attributable to persons who were our employees on the date of exercise. Additionally, we have been informed by Transocean that from January 1, 2005 to December 31, 2005, our current and former employees and directors have realized $85.3 million of gains from the exercise of Transocean stock options with $4.3 million relating to persons who were our employees on the date of exercise. If Transocean’s interpretation of the tax sharing agreement prevails, we would recognize a tax benefit for former employee and director stock option exercises and pay Transocean 35% for the deduction. While this would not increase our tax expense, it would defer utilization of pre-IPO income tax benefits.
Years Ended December 31, 2004 and 2003
Operating Revenues. Total operating revenues increased $123.7 million, or 54%, during 2004 as compared to 2003. The increase in operating 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.
Operating 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.
Operating 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.
Operating 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 operating 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 and maintenance expenses 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 and maintenance expenses 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 “- Variable Interest Entity - Delta Towing.”
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.”
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 certain 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 20 to our consolidated financial statements included in Item 8 of this report for a discussion of discontinued operations.
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 “- Variable Interest Entity - Delta Towing.” See Note 4 to our consolidated financial statements included in Item 8 of this report.
Financial Condition
At December 31, 2005 and December 31, 2004, we had total assets of $825.0 million and $761.4 million, respectively. The $63.6 million increase in assets during 2005 is primarily attributable to an increase in cash and cash equivalents resulting from the increased dayrates and utilizations experienced throughout 2005 ($97.9 million), a $44.6 million increase in our accounts receivable primarily due to the increased dayrates, capital expenditures of $22.4 million and the recognition of an additional $4.9 million in deferred income tax assets in 2005. These increases were partly offset by depreciation of $96.0 million, $1.2 million in net amortization of deferred preparation and mobilization cost and the sale of assets with a net book value of $10.7 million. See “- Liquidity and Capital Resources.” Total assets by business segment were as follows for the periods indicated below:
Working capital at December 31, 2005 was $143.1 million, as compared to a working capital of $61.2 million at December 31, 2004. The increase in working capital during 2005 is primarily attributable increases in cash and accounts receivable resulting from higher dayrates and utilization rates for our drilling rigs for the year ended December 31, 2005.
Liquidity and Capital Resources
Sources and Use of Cash
2005 Compared to 2004. Net cash provided by operating activities was $136.4 million for the year ended December 31, 2005, as compared to $57.7 million in 2004. The $78.7 million increase in net cash provided by operating activities is primarily attributable to the increase in net income of $88.2 million. Adjustments to reconcile net income to net cash provided by operating activities were lower in 2005, primarily due to unfavorable variances related to an increase in deferred income taxes of $10.0 million, a $4.5 million decrease in stock compensation
expense recognized by us in 2005 as compared to 2004, the $4.7 million loss in 2004 related to impairment of three lake barges in Venezuela and the retirement of related party debt and the additional $18.6 million in gains recognized from asset sales in 2005. These were partially offset by a favorable variance resulting from an increase in deferred income recognized during 2005 of $9.0 million. Changes in operating assets and liabilities, net of effect of distributions to Transocean, resulted in a $14.4 million increase in cash in 2005, compared to a $4.3 million reduction in 2004. This $18.7 million favorable increase is primarily the result of the increase in net taxes payable due to current year income ($29.8 million) and the increase in accounts payable and other current liabilities resulting from the increased levels of activity ($32.0 million). These increases were partly offset by the increase in accounts receivable which had an unfavorable impact of $36.0 million when reconciling net income to net cash provided by operating activities. Higher revenues, the result of increasing dayrates and utilizations, during 2005 resulted in a significantly higher receivable balance at year end when compared to year end 2004.
Net cash provided by investing activities was $13.4 million for the year ended December 31, 2005 compared to $0.4 million for the same period in 2004. The $13.0 million increase in net cash provided by investing activities relates primarily to the higher proceeds recognized from asset sales during the year of $23.0 million offset by the increase in capital expenditures of $10.0 million.
Net cash used in financing activities was $51.9 million for the year ended December 31, 2005, as compared to $13.0 million for the same period in 2004. Financing activities in 2005 included the special cash dividend of $61.2 million, the $7.7 million repayment of our 6.75% notes, the receipt of $17.8 million related to the issuance of common stock under our long-term incentive plans and the repayment of capital leases totaling $0.8 million. 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.
Sources of Liquidity and Capital Expenditures
Our cash flows from operations, asset sales and existing cash balances were our primary sources of liquidity for the years ended December 31, 2005 and 2004.
For the year ended December 31, 2005, our primary uses of cash were operating costs, the special cash dividend payment of $61.2 million, capital expenditures of $22.4 and debt repayments of $7.7 million. 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. At December 31, 2005, we had $163.0 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 (the “2003 Facility”) that declined to $60 million in December 2004. The 2003 Facility expired in December 2005 at which time we entered into a two-year, $200 million floating-rate secured revolving credit facility (the “2005 Facility”). The 2005 Facility is secured by most of our drilling rigs, receivables, the stock of most of its U.S. subsidiaries and is guaranteed by some of its subsidiaries. Borrowings under the 2005 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 1.25% or (2) the London Interbank Offering Rate (LIBOR) plus a margin of 1.60%. Commitment fees on the unused portion of the 2005 Facility are 0.55% of the average daily available portion and are payable quarterly. Borrowings and letters of credit issued under the 2005 Facility may not exceed the lesser of $200 million or one third of the fair market value of the drilling rigs securing the facility, as determined from time to time by a third party approved by the agent under the facility.
Financial covenants include maintenance of the following:
•
a working capital ratio of (1) current assets plus unused availability under the facility to (2) current liabilities of at least 1.2 to 1,
•
a ratio of total debt to total capitalization of not more than 0.35 to 1.00,
•
tangible net worth of not less than $375 million, and
•
in the event availability under the facility is less than $50 million, a ratio of (1) EBITDA (earnings before interest, taxes, depreciation and amortization) minus capital expenditures to (2) interest expense of not less than 2 to 1, for the previous four fiscal quarters.
The revolving credit facility provides, among other things, for the issuance of letters of credit that we may utilize to guarantee its performance under some drilling contracts, as well as insurance, tax and other obligations in various jurisdictions. The 2005 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.
At December 31, 2005 and 2004, we had no borrowings outstanding under either of the 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 ($2.1 million U.S. dollars at the current exchange rate at December 31, 2005) 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 at our option. However, if not repaid within 30 days, the promissory notes may be renewed at mutually agreeable terms for an additional 30-day period at the then designated interest rate. There are no commitment fees payable on the unused portion of the line of credit, and the facility is reviewed annually by the bank’s board of directors. At December 31, 2005, we had a balance of $0.4 million outstanding under this line of credit. There were no borrowings outstanding under this line of credit at December 31, 2004.
We expect capital expenditures primarily for rig refurbishments and the purchase of capital equipment to be approximately $37 million in 2006, including approximately $22 million for announced rig reactivations. The timing and amounts we actually spend in connection with our plans to upgrade and refurbish other selected rigs 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 cold stacked rigs requiring 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 market conditions should provide us an opportunity to obtain in 2006 term contracts with customers for the reactivation and return to service of all five of our remaining cold stacked U.S. Gulf of Mexico jackup rigs. Approximately $55 to $60 million in the aggregate would be required to return these rigs to service, based on our cost projections for these future reactivations. Additionally, we anticipate that we should be able to obtain in 2006 term contracts with customers to reactivate and return to service two or three of our cold stacked 2,000 or 3,000 horsepower inland barge rigs. Based upon our historical experience and previous rig reactivation assessments we believe the estimated costs to prepare these two or three inland barge rigs for service would be approximately $6 to $10 million per rig. The amounts we estimate for restoring cold stacked rigs to service are based on our projections of the costs of equipment, supplies and services, which have been rising and are becoming more difficult to project. In addition to the uncertainty of projecting costs in a time of increasing prices, our estimates of rig reactivation costs are also subject to numerous other variables including further rig deterioration over time, the availability and cost of shipyard facilities, customer specifications, and the actual extent of required repairs and maintenance and optional upgrading of the rigs. The actual amounts we ultimately pay for returning these rigs to service could, therefore, vary substantially from our estimates. In anticipation of reactivating some of these rigs, we have already placed orders for equipment with long lead times, including a $4.4 million commitment
for three top-drives with an 18-month option for ten additional top-drive units and $12.9 million of drill pipe for delivery in 2006.
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.
Dividend Policy
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. Subject to Delaware law, 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. However, due to favorable market conditions, our unrestricted cash balances grew to levels that exceeded our foreseeable needs for cash held for reinvestment and unknown contingencies. After we secured the approval of our lenders, our board of directors declared a special cash dividend of $1.00 per share, totaling $61.2 million, that was paid in August 2005. This special cash dividend is not indicative of a change in our basic dividend policy nor does it guarantee that any future dividends will be paid.
In connection with the special cash dividend and as contemplated by our long term incentive plans, our Executive Compensation Committee awarded special cash bonuses to holders of stock options under our long term incentive plans in the aggregate amount of $0.7 million to compensate them for any potential loss in option value. These bonuses were paid in the third quarter of 2005.
Contractual Obligations
As of December 31, 2005, our scheduled debt maturities and other contractual obligations are presented in the table below with debt obligations presented at face value:
At December 31, 2005, 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 Mexico, Trinidad and Venezuela.
(a)
Relates to bonds issued primarily in connection with our contracts with PEMEX, PDVSA and Trinidad.
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, 2005, 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, 2005, we did not have any outstanding interest rate swaps.
Variable Interest Entity - Delta Towing
In January 2006, we purchased Chouest’s 75% interest in Delta Towing for one dollar and paid $1.1 million to retire Delta Towing’s related party debt to Chouest. As a result of the consolidation of Delta Towing in our consolidated financial statements in accordance with FIN 46 beginning December 31, 2003, the purchase of the additional interest in Delta Towing is not expected to have a material impact on our consolidated results of operations, financial position or cash flows. See Note 4 to our consolidated financial statements included in Item 8 of this report.
We owned, as of December 31, 2005, 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 $34.0 million at December 31, 2005, are collateral for our notes receivable from Delta Towing. The remaining 75% ownership interest was held by Chouest which also loaned Delta Towing $3.0 million. See “- Related Party Transactions - Long-Term Debt - Chouest.”
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 failure to make its quarterly interest payments. The default continued in 2004 and 2005 when Delta Towing
failed to make 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. 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 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, 2005 and 2004, 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 years ended December 31, 2005 and 2004.
Prior to December 31, 2003, we accounted for our investment in Delta Towing under the equity method and recorded $6.6 million in equity losses for the year ended December 31, 2003, as a reduction in the carrying value of Delta Towing’s notes receivable held by us. In addition, during the year ended December 31, 2003, we earned interest income of $3.3 million 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. 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.
Related Party Transactions
Long-Term Debt - Chouest
In connection with the acquisition of the marine business, Delta Towing entered into a $3.0 million note agreement with Chouest dated January 30, 2001. As of December 31, 2005, the balance outstanding under the note is $2.9 million. The note bears interest at 8%, payable quarterly. In January 2004, Delta Towing failed to make its scheduled principal payment to Chouest and the $2.9 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 Chouest from proceeds from the sales of marine vessels. In conjunction with our purchase of Chouest’s 75% in Delta Towing in January 2006, we paid $1.1 million to retire the $2.9 million note payable. Interest expense related to the note payable to Chouest was $0.2 and $0.3 million for the years ended December 31, 2005 and 2004, respectively.
Allocation of Administrative Costs
Prior to the IPO, Transocean historically provided specified administrative support to us. Transocean charged us a proportional share of its administrative costs based on estimates of the percentage of work each Transocean department performed for us. The amount of expense allocated to us was $1.4 million for the year ended December 31, 2003 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.
Long-Term Debt - Transocean
We were party to a $1.8 billion two-year revolving credit agreement (the “Transocean Revolver”) with Transocean, dated April 6, 2001. During the year ended December 31, 2003, we recognized $0.8 million 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, 2005, we had approximately $2.2 million, $3.5 million and $10.2 million principal amount of the 6.95%, 7.375% and 9.5% Senior Notes, respectively, 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 increased by approximately $0.5 million.
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. We recognized $42.7 million in interest expense related to these notes for the year ended December 31, 2003.
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 for the year ended December 31, 2003. 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.
Asset Transfers to Transocean
We transferred certain 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. See Note 20 to our consolidated financial statements included in Item 8 of this report.
Other Transactions Between Us and Transocean
In September 2005, Transocean instructed us, pursuant to a provision in the tax sharing agreement, to take a tax deduction for profits realized by our current and former employees and directors from the exercise of Transocean stock options during calendar 2004. Transocean also indicated that it expected us to take a similar deduction in future years to the extent there were profits realized by our current and former employees and directors during those future periods.
It is our belief that the tax sharing agreement only requires us to pay Transocean for deductions related to stock option exercises by persons who were our employees on the date of exercise. Transocean disagreed with our interpretation of the tax sharing agreement as it relates to this issue and it believes that we must pay for all stock option exercises, irrespective of whether any employment or other service provider relationship may have terminated prior to the exercise of the employee stock option. As such, Transocean initiated dispute resolution proceedings against us.
We recorded our obligation to Transocean based upon our interpretation of the tax sharing agreement. However, due to the uncertainty of the outcome of this dispute, we established a reserve equal to the benefit derived from stock option deductions relating to persons who were not our employees on the date of the exercise. For the tax year ending December 31, 2004, the deduction related to all of our current and former employees and directors was $8.8 million with only $1.1 million attributable to persons who were our employees on the date of exercise. Additionally, we have been informed by Transocean that from January 1, 2005 to December 31, 2005, our current and former employees and directors have realized $85.3 million of gains from the exercise of Transocean stock options with $4.3 million relating to persons who were our employees on the date of exercise. If Transocean’s interpretation of the tax sharing agreement prevails, we would recognize a tax benefit for former employee and director stock option exercises and pay Transocean 35% for the deduction. While this would not increase our tax expense, it would defer utilization of pre-IPO income tax benefits.
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 master separation agreement 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 2005, we recorded an additional $7.7 million in pre-IPO deferred state tax liabilities that existed at the IPO date. The recognition of these pre-IPO deferred state tax liabilities resulted in a $7.7 million reduction in additional paid-in capital, $0.9 million of deferred state tax benefit and a $6.8 million increase in deferred tax liabilities.
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:
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our strategy,
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improvement in the fundamentals of the oil and gas industry,
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the supply and demand imbalance in the oil and gas industry,
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the correlation between demand for our rigs, our earnings and our customers’ expectations of energy prices,
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our plans, expectations and any effects of focusing on agreements and marine assets and drilling for natural gas along the U.S. Gulf Coast, pursuing efficient, low-cost operations and a disciplined approach to capital spending, maintaining high operating standards and maintaining a conservative capital structure,
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the emergence of the drilling industry from a low point in the cycle,
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estimated tax benefits and estimated payments under our tax sharing agreement with Transocean,
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expected capital expenditures,
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expected general and administrative expense,
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refurbishment costs,
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our ability to take advantage of opportunities for growth and our ability to respond effectively to market downturns,
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sufficiency of funds for required capital expenditures, working capital and debt service,
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deep gas drilling opportunities,
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operating standards,
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payment of dividends,
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competition for drilling contracts,
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matters relating to derivatives,
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matters related to our letters of credit and surety bonds,
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future restructurings,
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future transactions with unaffiliated third parties, including the possible sale of our Venezuelan assets,
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matters relating to our future transactions, agreements and relationship with Transocean,
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payments under agreements with Transocean,
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interests conflicting with those of Transocean,
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liabilities under laws and regulations protecting the environment,
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results and effects of legal proceedings,
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future utilization rates,
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future dayrates, and
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expectations regarding improvements in offshore drilling activity, demand for our drilling rigs, our plan to operate primarily in the U.S. Gulf Coast, operating revenues, operating and maintenance expense, insurance expense and deductibles, interest expense, debt levels and other matters with regard to outlook.
Forward-looking statements in this report are identifiable by use of the following words and other similar expressions:
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“anticipate,”
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“believe,”
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“budget,”
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“could,”
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“estimate,”
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“expect,”
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“forecast,”
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“intent,”
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“may,”
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“might,”
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“plan,”
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“potential,”
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“predict,”
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“project,” and
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“should.”
The following factors could affect our future results of operations and could cause those results to differ materially from those expressed in the forward-looking statements included in this Form 10-K:
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worldwide demand for oil and gas,
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exploration success by producers,
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demand for offshore and inland water rigs,
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our ability to enter into and the terms of future contracts,
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labor relations,
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political and other uncertainties inherent in non-U.S. operations (including exchange controls and currency fluctuations),
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the impact of governmental laws and regulations,
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the adequacy of sources of liquidity,
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uncertainties relating to the level of activity in offshore oil and gas exploration and development,
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oil and natural gas prices (including U.S. natural gas prices),
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competition and market conditions in the contract drilling industry,
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work stoppages,
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increases in operating expenses,
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extended delivery times for material and equipment,
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the availability of qualified personnel,
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operating hazards,
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war, terrorism and cancellation or unavailability of insurance coverage,
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compliance with or breach of environmental laws,
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the effect of litigation and contingencies,
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our inability to achieve our plans or carry out our strategy,
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the matters discussed in “Item 1A. - Risk Factors,” and
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other factors discussed in this Form 10-K.
Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those indicated. Investors and potential investors 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.
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, 2005:
(a)
Expected maturity amounts are based on the face value of debt and do not reflect fair market value of debt.
A large part of our cash investments would earn commensurately higher rates of return if interest rates increase. Using December 31, 2005 cash investment levels, a one percent increase in interest rates would result in approximately $1.6 million of additional interest income per year.
Foreign Exchange Risk
Our international operations in Angola, Colombia, 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, 2005, 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 necessary due to the continuing political instability in Venezuela and the continuation of foreign exchange controls, which limited our ability to convert local currency into U.S. dollars and transfer excess funds out of Venezuela. In March 2005 and September 2004, we reversed $0.5 million and $0.7 million, respectively, 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, 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. As a result of the March 2005 reversal, we no longer have a currency valuation allowance. 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.
Item 8.
Item 8.
Financial Statements and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Management’s Report on Responsibility for Financial Statements
Management is responsible for the Consolidated Financial Statements and the other financial information contained in this Annual Report on Form 10-K. The financial statements have been prepared in accordance with generally accepted accounting principles and are considered by management to present fairly the company’s financial position, results of operations and cash flows. The financial statements include some amounts that are based on management’s best estimates and judgments. The financial statements have been audited by the company’s independent registered public accounting firm, Ernst & Young LLP. The purpose of their audit is to express an opinion as to whether the Consolidated Financial Statements included in this Annual Report on Form 10-K present fairly, in all material respects, the company’s financial position, results of operations and cash flows. Their report is presented on the following page.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of TODCO
We have audited the accompanying consolidated balance sheets of TODCO and Subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2005. 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as 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, 2005 and 2004, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, 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.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of TODCO’s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2006 expressed an unqualified opinion thereon.
As discussed in Note 2 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards Interpretation No. 46 effective December 31, 2003.
/s/ ERNST & YOUNG LLP
Houston, Texas
February 27, 2006
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of TODCO
We have audited management’s assessment, included in the accompanying Management’s Report on Responsibility for Internal Control Over Financial Reporting, that TODCO maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). TODCO’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the company’s internal control over financial reporting based on our audit.
We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that TODCO maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, TODCO maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the COSO criteria.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of TODCO and Subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2005 of TODCO and our report dated February 27, 2006 expressed an unqualified opinion thereon.
/s/ ERNST & YOUNG LLP
Houston, Texas
February 27, 2006
TODCO AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
See accompanying notes.
TODCO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
See accompanying notes.
TODCO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
See accompanying notes.
TODCO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
See accompanying notes.
TODCO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying notes.
TODCO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 - Nature of Business
TODCO (together with its subsidiaries and predecessors, unless the context requires otherwise, the “Company,” “we” or “our”), is a leading provider of contract oil and gas drilling services, primarily in the United States (“U.S.”) Gulf of Mexico shallow water and inland marine region, an area referred to as the U.S. Gulf Coast. The Company owns 64 drilling rigs, consisting of 24 jackup rigs, 27 inland barge rigs, three submersible rigs, one platform rig and nine land rigs. The Company contracts its drilling rigs, related equipment and work crews primarily on a dayrate basis to drill oil and natural gas wells. The Company also operates a fleet of 49 inland tugs, 22 offshore tugs, 36 crew boats, 33 deck barges, 17 shale barges, five spud barges and two offshore barges.
Effective January 31, 2001, a merger transaction between the Company and Transocean Inc. (“Transocean”) was completed (the “Transocean Merger”). A change of control occurred and the Company became an indirect wholly owned subsidiary of Transocean.
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 the Company. During 2003, the Company completed the transfer to Transocean of all assets not related to its Shallow Water business (“Transocean Assets”), including the transfer of all revenue-producing Transocean Assets. Accordingly, the Transocean Assets and related operations have been reflected as discontinued operations in the Company’s historical financial statements and notes thereto. The Company’s historical financial statements and the notes thereto have been restated for the effect of discontinued operations for all periods presented, except for the statement of cash flows and related Note 11 for which restatement is not required. See Note 20.
In February 2004, the Company completed an initial public offering, with Transocean selling 13,800,000 shares of its TODCO Class A common stock (the “IPO”). After several secondary stock offerings and a private sale in 2004 and 2005, Transocean had converted all of its unsold shares of Class B common stock into an equal number of shares of Class A common stock and had sold all of its remaining shares of the Company’s Class A common stock. As a result of the conversion, no Class B common stock is outstanding as of December 31, 2005. The Company received no proceeds from any of these sales. See Note 3.
Note 2 - Summary of Significant Accounting Policies and Basis of Consolidation
Basis of Consolidation - Intercompany transactions and accounts have been eliminated. For investments in joint ventures that either do not meet the criteria of being a variable interest entity or where the Company is not deemed to be the primary beneficiary for accounting purposes, the equity method of accounting is used where the Company’s ownership in the joint venture is between 20 percent and 50 percent and for investments in joint ventures where more than 50 percent is owned and the Company does not have control of the joint venture. The cost method of accounting is used for investments in joint ventures where the Company’s ownership is less than 20 percent and the Company does not have significant influence over the joint venture. For investments in joint ventures that meet the criteria of a variable interest entity and where the Company is deemed to be the primary beneficiary for accounting purposes, such entities are consolidated (see Variable Interest Entities).
Accounting Estimates - The preparation of consolidated financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and disclosure of contingent assets and liabilities. The Company evaluates its estimates on an ongoing basis, including those related to bad debts, materials and supplies obsolescence, investments, property and equipment and other long-lived assets, income taxes, personal injury claim liabilities, employment benefits and contingent liabilities. The Company bases its estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from such estimates.
TODCO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Segments - The Company’s operations have been aggregated into four reportable business segments, which for our contract drilling services correspond to the principal geographic regions in which the Company operates:
•
U.S. Gulf of Mexico Segment - The Company currently has 18 jackup and three submersible rigs in the U.S. Gulf of Mexico shallow water market which begins at the outer limit of the transition zone and extends to water depths of about 350 feet. The Company’s jackup rigs in this market consist of independent leg cantilever type units, mat-supported cantilever type rigs and mat-supported slot type jackup rigs that can operate in water depths up to 250 feet.
•
U.S. Inland Barge Segment - The Company’s barge rig fleet in this market consists of 12 conventional and 15 posted barge rigs. These units operate in marshes, rivers, lakes and shallow bay or coastal waterways that are known as the “transition zone”. This area along the U.S. Gulf Coast, where jackup rigs are unable to operate, is the world’s largest market for this type of equipment.
•
Other International Segment - The Company’s other international operations are currently conducted in Angola, Colombia, Mexico, Trinidad and Venezuela. The Company operates one jackup rig in Angola and one jackup rig in Colombia. In Mexico, the Company operates two jackup rigs and a platform rig. Additionally, the Company has two jackup rigs and one land rig in Trinidad and eight land rigs in Venezuela. The Company may pursue selected opportunities in other international areas from time to time.
•
Delta Towing Segment - The Company has a partial interest in a joint venture that operates a fleet of U.S. marine support vessels consisting primarily of shallow water tugs, crewboats and utility barges (“Delta Towing”). See Notes 4 and 21.
Cash and Cash Equivalents - Cash equivalents are stated at cost plus accrued interest, which approximates fair value. Cash equivalents are highly liquid investments with an original maturity of three months or less. Generally, the maturity date of the Company’s cash equivalent investments is the next business day. As of December 31, 2005, the Company had $85.7 million in Euro dollar time deposits. As of December 31, 2005 and 2004, the Company had $12.2 million and $11.9 million, respectively, of restricted cash to support four performance bonds issued in connection with our contracts with Pemex Exploration and Production (“PEMEX”), the Mexican national oil company. This restricted cash is included in other non-current assets on the consolidated balance sheet.
Accounts Receivable and Allowance for Doubtful Accounts - Accounts receivable trade are stated at the historical carrying amount net of write-offs and allowance for doubtful accounts receivable. Interest receivable on delinquent accounts receivable is included in the accounts receivable trade balance and recognized as interest income when chargeable and collectibility is reasonably assured. Uncollectible accounts receivable trade are written off when a settlement is reached for an amount that is less than the outstanding historical balance. The Company establishes an allowance for doubtful accounts receivable on a case-by-case basis when it believes the collection of specific amounts owed is unlikely to occur. This allowance was $0.4 million and $0.2 million at December 31, 2005 and 2004, respectively.
Materials and Supplies - Materials and supplies are carried at the lower of average cost or market less an allowance for obsolescence. Such allowance was $0.3 million at December 31, 2005 and 2004, respectively.
Property and Equipment - Property and equipment, consisting primarily of offshore drilling rigs and related equipment, represented approximately 58 percent of the Company’s total assets at December 31, 2005. The carrying values of these assets are based on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values of the Company’s rigs. These estimates, assumptions and judgments reflect both historical experience and expectations regarding future industry conditions and operations. The Company provides for depreciation using the straight-line method after allowing for salvage values. Estimated useful lives of drilling units range from 10 to 15 years for the majority of the Company’s drilling units. Expenditures for renewals, replacements and improvements are capitalized. Maintenance and repairs are charged to operating expense as incurred. Upon sale
TODCO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
or other disposition to third parties, the applicable amounts of asset cost and accumulated depreciation are removed from the accounts and the net amount, less proceeds from disposal, is charged or credited to income.
Impairment of Other Long-Lived Assets - The carrying value of long-lived assets, principally property and equipment, is reviewed for potential impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable as prescribed by the Financial Accounting Standard Board’s (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 144, Accounting for Impairment on Disposal of Long-Lived Assets (“SFAS 144”). For property and equipment held for use, the determination of recoverability is made based upon the estimated undiscounted future net cash flows of the related asset or group of assets being evaluated. Property and equipment held for sale are recorded at the lower of net book value or net realizable value. See Note 10.
Operating Revenues and Expenses - Operating revenues are recognized as earned, based on contractual daily rates. In connection with drilling contracts, the Company may receive revenues for preparation and mobilization of equipment and personnel or for capital improvements to rigs. In connection with new drilling contracts, revenues earned and incremental costs incurred directly related to the preparation and mobilization of the rig are deferred and recognized over the primary contract term of the drilling project for contracts that have a primary contract term of two months or longer and where such amounts are material. Costs of relocating drilling units without contracts to more promising market areas are expensed as incurred. Revenues and expenses associated with the demobilization of drilling units are recognized upon completion of the related drilling contracts. Capital upgrade revenues received are deferred and recognized over the primary contract term of the drilling project. The actual cost incurred for the capital upgrade is depreciated over the estimated remaining useful life of the asset.
At December 31, 2005 and 2004, $17.8 million and $19.0 million, respectively, in deferred contract preparation and mobilization costs were included in other assets in the Company’s consolidated balance sheets. During the years ended December 31, 2005, 2004 and 2003, the Company amortized $11.2 million, $12.0 million and $1.2 million, respectively, of these costs to expense, which is included in operating and maintenance expense in the Company’s consolidated statements of operations.
Variable Interest Entities - In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51 (“FIN 46”). FIN 46 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. The Company adopted and applied the provisions of FIN 46, as amended, effective December 31, 2003. See Note 4.
Foreign Currency Translation - The Company accounts for translation of foreign currency in accordance with SFAS No. 52, Foreign Currency Translation. The majority of the Company’s revenues and expenditures are denominated in U.S. dollars to limit the Company’s exposure to foreign currency fluctuations, resulting in the use of the U.S. dollar as the functional currency for all of the Company’s operations. Foreign currency translations and exchange gains and losses are included in other income (expense), net as incurred. Net foreign currency exchange gains (losses) were $0.8 million, $1.7 million and $(2.7) million for the years ended December 31, 2005, 2004 and 2003, respectively.
Income Taxes - Income taxes have been provided based upon the tax laws and rates in the countries in which operations are conducted and income is earned. Deferred tax assets and liabilities are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of the Company’s assets and liabilities using the applicable tax rates in effect at year end. A valuation allowance for deferred tax assets is recorded when it is more likely than not that some or all of the benefit from the deferred tax asset will not be
TODCO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
realized. In conjunction with the IPO, the Company entered into a tax sharing agreement with Transocean. See Notes 12 and 13.
Stock-Based Compensation - Through December 31, 2002 and in accordance with the provisions of SFAS No. 123, Accounting for Stock-based Compensation (“SFAS 123”), the Company elected to follow the Accounting Principles Board Opinion (“APB”) No. 25, Accounting for Stock Issued to Employees (“APB 25”), and related interpretations in accounting for awards under its employee stock-based compensation plans using the intrinsic value method. Under the intrinsic value method of APB 25, no compensation expense was recognized if the exercise price of the employee stock options was less than the fair value of the underlying stock on the date of grant. If an employee stock option was modified subsequent to the original grant date, and the exercise price was less than the fair value of the underlying stock on the date of the modification, compensation expense equal to the excess of the fair value over the exercise price was recognized over the remaining vesting period.
Effective January 1, 2003, the Company adopted the fair value method of accounting for stock-based compensation using the prospective method of transition under SFAS 123. Under the prospective method and in accordance with the provisions of SFAS No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure, the recognition provisions are applied to all employee awards granted, modified or settled after January 1, 2003. See Note 14 for a discussion of awards under the Company’s long-term incentive plan during the year ended December 31, 2005.
If the Company had elected to adopt the fair value recognition provisions of SFAS 123 as of its original effective date, pro forma net income (loss) and diluted net income (loss) per share would have been as follows for the years ended December 31, 2004 and 2003 (in millions, except per share amounts):
In conjunction with the IPO in February 2004, the Company recognized all future stock-based compensation expense related to Transocean stock options granted to employees. As a result, the Company no longer has any reconciling items between reported net income and pro forma net income as all stock-based employee compensation expense included in reported net income after the IPO is calculated under the fair value method promulgated by SFAS 123.
See Note 14 of the Notes to Consolidated Financial Statements for a discussion of the Company’s long-term incentive plan activity for the years ended December 31, 2005 and 2004. There were no outstanding awards under the Company’s long-term incentive plan at December 31, 2003.
New Accounting Pronouncements - In December 2004, the FASB issued SFAS No. 123 (revised 2004), Share-Based Payment (“SFAS 123(R)”), which is a revision of SFAS No. 123. SFAS 123(R) supersedes APB 25 and amends SFAS No. 95, Statement of Cash Flows. Generally, the approach to accounting for share-based payments in SFAS 123(R) is similar to the approach described in SFAS 123. However, SFAS 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements
TODCO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
based on their fair values (i.e., pro forma disclosure is no longer an alternative to financial statement recognition). SFAS 123(R) is effective for the Company beginning January 1, 2006. As the Company has already adopted SFAS 123, the Company’s adoption of SFAS 123(R) is not expected to have a material impact on the Company’s consolidated results of operations, financial position or cash flows.
In December 2004, the FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29 (“SFAS 153”). This Statement amends APB Opinion No. 29 to permit the exchange of nonmonetary assets to be recorded on a carry over basis when the nonmonetary assets do not have commercial substance. This is an exception to the basic measurement principle of measuring a nonmonetary asset exchange at fair value. A nonmonetary asset exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The Company adopted SFAS 153 effective April 1, 2005, and the adoption did not have a material effect on its consolidated results of operations, financial position or cash flows.
In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections (“SFAS 154”). SFAS 154 is a replacement of APB Opinion No. 20, Accounting Changes, and FASB Statement No. 3, Reporting Accounting Changes in Interim Financial Statements. SFAS 154 applies to all voluntary changes in accounting principle and changes the accounting for and reporting of a change in accounting principle. SFAS 154 requires retrospective application to prior periods’ financial statements of a voluntary change in accounting principle unless it is impracticable. Previously, most voluntary changes in accounting principle were required to be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The Company does not anticipate the adoption of SFAS 154 to have a material effect on its financial condition or results of operations.
Note 3 - Capital Stock and Related Transactions
Capital Structure - In February 2004, the Company amended its articles of incorporation to, among other things, create two classes of common stock, Class A and Class B, increase its authorized capital stock and to convert any issued and outstanding shares of the Company’s common stock into Class B common stock. As amended, the Company’s authorized capital stock consists of (i) 500,000,000 shares of Class A common stock, par value $.01 per share, and 260,000,000 shares of Class B common stock, par value $.01 per share, and (ii) 50,000,000 shares of preferred stock, par value $.01 pershare.
Capital Stock Transactions and Retirement of Related Party Debt - In February 2004, prior to the Company’s IPO, the Company exchanged $45.8 million in principal amount of its outstanding 7.375% Senior Notes held by Transocean Holdings Inc. (a wholly owned subsidiary of Transocean, “Transocean Holdings”), plus accrued interest thereon, for 359,638 shares of the Company’s Class B common stock (4,367,714 shares of Class B common stock after giving effect to the stock dividend discussed below). Immediately following this exchange, the Company exchanged $152.5 million and $289.8 million principal amount of its outstanding 6.75% and 9.5% Senior Notes, respectively, held by Transocean, plus accrued interest thereon, for 3,580,768 shares of the Company’s Class B common stock (43,487,535 shares of Class B common stock after giving effect to 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. Additionally, the Company expensed the remaining balance of deferred consent fees associated with these notes and recognized a $1.9 million loss on retirement of debt.
Immediately following the debt-for-equity exchanges, the Company declared a dividend of 11.145 shares of its Class B common stock with respect to each share of its Class B common stock outstanding. The stock dividend of 11.145 shares of Class B common stock for each outstanding share of Class B common stock was retroactively applied to the 1,000,000 shares of common stock held by Transocean prior to the debt-for-equity exchanges and has
TODCO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
been reflected in the Company’s historical consolidated financial statements. The effect of this retroactive application was to increase the authorized common shares of the Company’s Class B common stock to 260,000,000 shares, and issued and outstanding to 12,144,751 shares, as of December 31, 2003 with a corresponding decrease to additional paid-in capital.
As a result of the debt-for-equity exchanges and stock dividend, Transocean held an aggregate of 60,000,000 shares of Class B common stock prior to the closing of the IPO. A portion of these shares (13,800,000) of Class B common stock was converted into shares of Class A common stock and sold in the IPO.
Also in connection with the closing of the IPO, Transocean made additional equity contributions totaling $2.8 million, including $1.0 million in intercompany payable balances owed by the Company to Transocean as of the IPO date.
Initial Public Offering and Related Events - In February 2004, the Company completed the IPO, with Transocean selling 13,800,000 shares of TODCO Class A common stock at $12.00 per share. The Company did not receive any proceeds from the initial sale of Class A common stock.
Before completion of the IPO, the Company entered into various agreements to complete the separation of the Shallow Water business from Transocean, including an employee matters agreement, a master separation agreement and a tax sharing agreement. The master separation agreement provides for, among other things, the assumption by the Company of liabilities relating to the Shallow Water business and the assumption by Transocean of liabilities unrelated to the Shallow Water business, including the indemnification of losses that may occur as a result of certain of the Company’s ongoing legal proceedings. See Note 13.
In February 2004, the Company recorded an increase in equity related to net liabilities attributable 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 master separation agreement between the Company and Transocean. The indemnification by Transocean was recorded as a credit to additional paid-in capital and a corresponding related party receivable from Transocean.
In conjunction with the IPO, the Company entered into a tax sharing agreement with Transocean. See Note 12.
Secondary Stock Offerings - In September 2004, Transocean sold an additional 17,940,000 shares of TODCO Class A common stock at $15.75 per share in a secondary public offering. Prior to the completion of the secondary stock offering, Transocean converted 17,940,000 shares of the Company’s Class B common stock held by them into an equal number of shares of Class A common stock. The Company did not receive any proceeds from this offering.
In December 2004, Transocean sold 14,950,000 shares of its TODCO Class A common stock at $18.00 per share in a secondary public offering after conversion of an equivalent amount of shares of the Company’s Class B common stock held by them into Class A common stock. The Company did not receive any proceeds from the sale of stock in this offering. Upon completion of the secondary offering, Transocean converted all of its remaining Class B common stock, which is entitled to five votes per share, into the Company’s Class A common stock, which is entitled to one vote per share. As a result of this conversion, no Class B common stock is outstanding as of December 31, 2005 or 2004. After the December 2004 secondary public offering, Transocean owned 13,310,000 shares of the Company’s Class A common stock which were sold in a secondary public offering in May 2005. The Company did not receive any proceeds from the sale of stock in this offering.
Common Stock Dividend - On August 2, 2005, the Company’s Board of Directors declared a special cash dividend of $1.00 per common stock share, payable on August 25, 2005 to stockholders of record on August 15, 2005. The Company received a waiver from the lenders under its revolving credit facility to pay this special cash dividend of $61.2 million. In connection with the special cash dividend and as contemplated by the Company’s long term incentive plans, the Company’s Executive Compensation Committee awarded special cash bonuses to holders of stock options under the Company’s long term incentive plans in the amount of $0.7 million to compensate them for any potential loss in option value.
TODCO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 4 - Delta Towing
The Company owns a 25 percent equity interest in Delta Towing LLC (“Delta Towing”), a joint venture formed to own and operate the Company’s U.S. marine support vessel business, consisting primarily of shallow water tugs, crewboats and utility barges. The Company previously contributed its support vessel business to the joint venture in return for a 25 percent ownership interest and certain secured notes receivable from Delta Towing with a face value of $144.0 million. The Company valued these notes at $80.0 million immediately prior to the Transocean Merger. 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 $34.0 million at December 31, 2005, are collateral for the Company’s notes receivable. The remaining 75 percent ownership interest is held by an affiliate of Edison Chouest Inc. (“Chouest”), which also loaned $3.0 million to Delta Towing. See Notes 6 and 21.
As a result of its issuance of notes to the Company, 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 the Company’s continued evaluation of the collectibility of the notes, the Company recorded a $21.3 million impairment of the notes in September 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 in the notes in the event of default, the Company began offsetting a portion of the amount owed by the Company to Delta Towing against the interest due under the notes. Additionally, in 2003, the Company established a $1.6 million reserve for interest income earned during the quarter on the notes receivable. During the year ended December 31, 2003, the Company earned interest income of $3.3 million relating to amounts loaned to Delta Towing.
Under FIN 46, Delta Towing is considered a VIE because its equity is not sufficient to absorb the joint venture’s expected future losses. The Company is deemed to be the primary beneficiary of Delta Towing for accounting purposes because it has the largest percentage of investment at risk through the secured notes held by the Company and would thereby absorb the majority of the expected losses of Delta Towing. The Company adopted FIN 46, as amended, and, accordingly, consolidated Delta Towing effective December 31, 2003. The consolidation of Delta Towing resulted in an increase in net assets and a corresponding gain of $0.8 million which has been presented as a cumulative effect of a change in accounting principle in the consolidated statement of operations for the year ended December 31, 2003. Prior to December 31, 2003, the Company accounted for its investment in Delta Towing under the equity method.
During the year ended December 31, 2003, the Company recognized a loss of $6.6 million related to its investment in Delta Towing. The loss attributable to Delta Towing in 2003 included the Company’s share of a $2.5 million non-cash impairment charge in the carrying value of idle equipment recorded by Delta Towing in December 2002, as well as a $1.9 million non-cash impairment charge in December 2003 as a result of Delta Towing’s annual test of impairment of long-lived assets.
As part of the formation of the joint venture on January 31, 2001, the Company entered into an agreement with Delta Towing under which the Company committed to charter certain vessels for a period of one year ending January 31, 2002 and committed to charter for a period of 2.5 years from the date of delivery 10 crewboats then under construction, all of which were in service as of December 31, 2004. During the year ended December 31, 2003, the Company incurred charges totaling $11.7 million from Delta Towing for services rendered which was reflected in operating and maintenance expense - related party in 2003.
As of December 31, 2005 and 2004, all intercompany accounts have been eliminated in consolidation as a result of the adoption of FIN 46, as well as all intercompany transactions during 2005 and 2004.
The creditors of Delta Towing have no recourse to the general credit of the Company.
TODCO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Investments in and Advances to Joint Ventures - At December 31, 2005 and 2004, the Company held a 20 percent investment in Offshore Towing, Inc. (“OTI”) as a result of the Company’s consolidation of Delta Towing under FIN 46. The investment in OTI, which is accounted for under the cost method of accounting, was $0.1 million at December 31, 2005 and 2004 and is reflected in other non-current assets on the Company’s balance sheet.
Note 5 - Venezuelan Working Capital Facility and Foreign Currency Matters
In the second quarter of 2003, the Company established a currency valuation allowance of $2.4 million pertaining to cash and receivables in Venezuela in order to adjust its Venezuelan financial assets to net realizable value as of June 30, 2003. This valuation allowance was necessary due to the continuing political instability in Venezuela and the continuation of foreign exchange controls, which limited the Company’s ability to convert local currency into U.S. dollars and transfer excess funds out of Venezuela. In March 2005 and September 2004, the Company reversed $0.5 million and $0.7 million, respectively, 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, primarily as a result of an agreement with the Company’s primary customer in Venezuela to pay the majority of the U.S. dollar denominated accounts receivable in U.S. dollars to one of the Company’s banks in the United States. As a result of the March 2005 reversal, the Company no longer has a currency valuation allowance. On March 3, 2005, Venezuela increased the official exchange rate from 1,920 bolivars per 1 U.S. dollar to 2,150 bolivars per 1 U.S. dollar. The Company does not anticipate that this change in the exchange rate will have a material effect on its consolidated results of operations, financial condition or cash flows.
Additionally, in response to the increase in U.S. dollar remittances, the Company entered into an unsecured line of credit with a bank in Venezuela in the third quarter of 2004 to provide a maximum of 4.5 billion Venezuela Bolivars ($2.1 million U.S. dollars at the current exchange rate at December 31, 2005) in order to establish a source of local currency to meet the current obligations in Venezuela Bolivars as necessary. 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 which is currently 16%. The promissory notes are pre-payable at any time at the Company’s option. However, if not repaid within 30 days, the promissory notes may be renewed at mutually agreeable terms for an additional 30-day period at the then designated interest rate. There are no commitment fees payable on the unused portion of the line of credit, and the facility is reviewed annually by the bank’s board of directors. At December 31, 2005, the Company had a balance of $0.4 million outstanding under this line of credit. There were no borrowings outstanding under this line of credit at December 31, 2004. The Company recognized $0.1 million in interest expense related to the line of credit for the year ended December 31, 2005. There was no interest expense recognized in 2004.
TODCO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 6 - Long-Term Debt and Capital Lease Obligations
Long-term debt and capital lease obligations, net of unamortized discounts, premiums, and fair value adjustments, were comprised of the following (in millions):
Third Party Debt - Revolving Credit Facility. In December 2003, the Company entered into a two-year $75 million floating-rate secured revolving credit facility (the “2003 Facility”) that declined to $60 million in December 2004. The 2003 Facility expired in December 2005 at which time the Company entered into a two-year, $200 million floating-rate secured revolving credit facility (the “2005 Facility”). The 2005 Facility is secured by most of the Company’s drilling rigs, receivables, the stock of most of its U.S. subsidiaries and is guaranteed by some of its subsidiaries. Borrowings under the 2005 Facility bear interest at the Company’s 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 1.25% or (2) the London Interbank Offering Rate (LIBOR) plus a margin of 1.60%. Commitment fees on the unused portion of the 2005 Facility are 0.55% of the average daily available portion and are payable quarterly. Borrowings and letters of credit issued under the 2005 Facility may not exceed the lesser of $200 million or one third of the fair market value of the drilling rigs securing the facility, as determined from time to time by a third party approved by the agent under the facility.
Financial covenants include maintenance of the following:
•
a working capital ratio of (1) current assets plus unused availability under the facility to (2) current liabilities of at least 1.2 to 1,
•
a ratio of total debt to total capitalization of not more than 0.35 to 1.00,
•
tangible net worth of not less than $375 million, and
•
in the event availability under the facility is less than $50 million, a ratio of (1) EBITDA (earnings before interest, taxes, depreciation and amortization) minus capital expenditures to (2) interest expense of not less than 2 to 1, for the previous four fiscal quarters.
The revolving credit facility provides, among other things, for the issuance of letters of credit that we may utilize to guarantee its performance under some drilling contracts, as well as insurance, tax and other obligations in various jurisdictions. The 2005 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.
TODCO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
During the years ended December 31, 2005 and 2004, the Company recognized $0.9 million and $1.2 million, respectively, in interest expense related to commitment fees on the unused portion of the 2003 Facility and amortized $1.2 million and $1.1 million, respectively, in deferred financing costs as a component of interest expense. At December 31, 2005 and 2004, the Company had no borrowings outstanding under either of the facilities.
Senior Notes and Exchange Offer - In March 2002, Transocean and the Company completed exchange offers and consent solicitations for the Company’s 6.5%, 6.75%, 6.95%, 7.375%, 9.125% and 9.5% Senior Notes (the “Exchange Offer”). As a result of the Exchange Offer, approximately $1.4 billion principal amount of the Company’s outstanding 6.5%, 6.75%, 6.95%, 7.375%, 9.125% and 9.5% Senior Notes were exchanged by Transocean for newly issued Transocean notes having the same principal amount, interest rate, redemption terms and payment and maturity dates (the “Exchanged Notes”). Both the Exchanged Notes and the notes not exchanged remained the obligation of the Company as Transocean became the holder of the Exchanged Notes. In December 2002, the Company repurchased from Transocean and retired approximately $501.2 million principal amount outstanding of the Exchanged Notes, including accrued and unpaid interest. The Exchanged Notes were acquired at current market values for each issuance, which were at a premium as compared to the face amount of the notes.
In April 2003, the Company repaid the entire $5.0 million principal amount outstanding of the 6.5% Senior Notes payable to third parties, plus accrued and unpaid interest, in accordance with their scheduled maturities. Also, in December 2003, the Company repaid all of the $10.2 million outstanding principal amount of its 9.125% Senior Notes in accordance with their scheduled maturities.
In the first half of 2003, the Company retired $529.7 million of its outstanding Exchanged Notes and other notes payable to Transocean (see “- Transocean Revolver”), in separate transactions, as consideration for the sale of certain of the Transocean Assets to Transocean, resulting in an aggregate pre-tax loss on retirement of debt of $79.5 million. See Note 20 for a further discussion of these individual transactions and retirement of related party debt.
In February 2004, prior to the Company’s IPO, the Company exchanged $488.1 million in principal amount of the then outstanding Exchanged Notes, plus accrued interest thereon, for 3,940,406 shares of the Company’s Class B common stock (47,855,249 shares of Class B common stock after giving effect to the stock dividend, as described in Note 3). In connection with the exchange, the Company recognized $3.1 million in interest expense related to the Exchange Notes in 2004. During the year ended December 31, 2003, the Company recognized $42.7 million in interest expense - related party related to these notes held by Transocean. There are no Exchanged Notes payable to Transocean outstanding as a result of the above transaction at December 31, 2005 and 2004.
In connection with the Exchange Offer, the Company had made an aggregate of $8.3 million in consent payments to holders of the notes that were exchanged. The consent payments were amortized as an increase to interest expense over the remaining terms of the exchanged notes using the interest method and resulted in $0.5 million being recognized as expense for the year ended December 31, 2003. No amounts were amortized to interest expense in 2005 or 2004. In connection with the retirement of the Exchanged Notes prior to the completion of the IPO, the Company expensed the remaining balance of these deferred consent fees of approximately $1.9 million in February 2004, which has been reflected as a loss on retirement of debt in the Company’s consolidated statement of operations.
In April 2005, the Company repaid the outstanding balance of $7.7 million related to the 6.75% Senior Notes. At December 31, 2005, approximately $2.2 million, $3.5 million, and $10.2 million principal amount of the 6.95%, 7.375%, and 9.5% Senior Notes, respectively, due to third parties were outstanding. The fair value of these notes at December 31, 2005 was approximately $2.2 million, $3.1 million, and $10.7 million, respectively, based on the estimated yield to maturity which takes into account TODCO’s credit worthiness. The Company recognized $1.3 million and $1.7 million, respectively, in interest expense related to these notes for the years ended
TODCO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
December 31, 2005 and 2004. After accounting for the effect of the amortization of the discounts, premiums and fair value adjustments on interest expense, the effective rates of the 6.95%, 7.375% and 9.5% Senior Notes are 6.81%, 7.36% and 7.2%, respectively.
Other Debt - Related Party - In connection with the acquisition of the U.S. marine support vessel business, Delta Towing entered into a $3.0 million note agreement with Chouest dated January 30, 2001. As of December 31, 2005, the balance outstanding under the note is $2.9 million. The note bears interest at 8 percent per annum, payable quarterly. The note has been classified as a current obligation in the Company’s consolidated balance sheet at December 31, 2005 and 2004 as Delta Towing remains in default on this note payable. The Company has no obligation to fund this debt on behalf of Delta Towing. Interest expense related to the note was $0.2 million and $0.3 million, respectively, for the years ended December 31, 2005 and 2004. In January 2006, the Company purchased Chouest’s 75% interest in Delta Towing for one dollar and paid $1.1 million to retire Delta Towing’s $2.9 million related party note to Chouest. As a result of the consolidation of Delta Towing in the Company’s consolidated financial statements in accordance with FIN 46 beginning December 31, 2003, the purchase of the additional interest in Delta Towing is not expected to have a material impact on the consolidated results of operations, financial position or cash flows of the Company.
Capital Lease Obligations - From time to time the Company enters into capital lease agreements for certain drilling equipment. In January 2004 and during 2003, the Company entered into three such capital lease agreements and exercised options to buy-out the remaining terms of these lease agreements for $2.3 million in the second quarter of 2004. In August 2004, the Company entered into a two-year capital lease agreement for $0.9 million with a final maturity date in July 2006. The Company exercised its option to buy-out the remaining term of this lease agreement in February 2005 for $0.7 million. The Company entered into additional capital lease agreements for $1.1 million each in January 2005 and June 2005. The Company exercised its option to buy-out the remaining term of these lease agreements in November 2005. As of December 31, 2005, the Company has no capital lease obligations. Interest expense which was not significant in 2005 and 2004 is included in interest expense. Depreciation expense on these assets which was not significant in 2005 or 2004 is included in depreciation expense.
Transocean Revolver - The Company was party to a $1.8 billion two-year revolving credit agreement (the “Transocean Revolver”) with Transocean dated April 6, 2001. Amounts outstanding under the Transocean Revolver bore interest quarterly at a rate of the London Interbank Offered Rate plus 0.575 percent to 1.3 percent depending on Transocean’s non-credit enhanced senior unsecured public debt rating. On April 6, 2003 the approximately $81.2 million then outstanding under the Transocean Revolver was converted into a 2.76 percent fixed rate promissory note, which was cancelled in full in connection with the sale of certain of the Transocean Assets to Transocean in September 2003. See Note 20.
Note 7 - Financial Instruments and Risk Concentration
Foreign Exchange Risk - The Company’s international operations expose the Company to foreign exchange risk. This risk is primarily associated with employee compensation costs denominated in currencies other than the U.S. dollar and with purchases from foreign suppliers. The Company may use a variety of techniques to minimize exposure to foreign exchange risk, including customer contract payment terms and foreign exchange derivative instruments.
The Company’s 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. Foreign exchange derivative instruments, specifically foreign exchange forward contracts, may be used to minimize foreign exchange risk in instances where the primary strategy is not attainable. A foreign exchange forward contract obligates the Company to exchange predetermined amounts of specified foreign currencies at specified exchange rates on specified dates or to make an equivalent U.S. dollar payment equal to the value of such exchange.
TODCO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Gains and losses on foreign exchange derivative instruments that qualify as accounting hedges are deferred as 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, 2005 and 2004, the Company did not have any outstanding foreign exchange derivative instruments.
Interest Rate Risk - The Company’s use of debt directly exposes the Company to interest rate risk. Fixed rate debt, in which the rate of interest is fixed over the life of the instrument and the instrument’s maturity is greater than one year, exposes the Company to changes in market rates of interest should the Company refinance maturing debt with new debt.
In addition, the Company is exposed to interest rate risk in its cash investments, as the interest rates on these investments change with market interest rates.
The Company, from time to time, may use interest rate swap agreements to manage the effect of interest rate changes on future income. These derivatives would be used as hedges and would not be used for speculative or trading purposes.
The major risks in using interest rate derivatives include changes in interest rates affecting the value of such instruments, potential increases in the interest expense of the Company due to market increases in floating interest rates, in the case of derivatives that exchange fixed interest rates for floating interest rates, and the creditworthiness of the counterparties in such transactions.
At December 31, 2005 and 2004, the Company did not have any interest rate swap agreements outstanding.
Credit Risk - Financial instruments that potentially subject the Company to concentrations of credit risk are primarily cash and cash equivalents and trade receivables. It is the Company’s practice to place its cash and cash equivalents in time deposits at commercial banks with high credit ratings or mutual funds that invest exclusively in high quality money market instruments. In foreign locations, local financial institutions are generally utilized for local currency needs. The Company limits the amount of exposure to any one institution and does not believe it is exposed to any significant credit risk.
The Company derives the majority of its revenue from services to international oil companies and government-owned and government-controlled oil companies. Receivables are concentrated in various countries (see Note 17). The Company maintains an allowance for doubtful accounts receivable based upon expected collectibility. The Company is not aware of any significant credit risks relating to its customer base and does not generally require collateral or other security to support customer receivables.
Employees - As of December 31, 2005, the Company had approximately 2,420 employees. As of December 31, 2005, approximately 219 (or 9%) of the Company’s employees worldwide were working under collective bargaining agreements, approximately 53 of whom were working in Trinidad and 166 of whom were working in Venezuela. The Company’s union agreement in Trinidad officially expired in August 2005. Negotiations are continuing on a new three year contract which, when executed, will be in effect until August 2008. None of the other agreements are expected to expire in 2006. Efforts have been made from time to time to unionize other portions of the Company’s workforce, including workers in the U.S. Gulf of Mexico.
Note 8 - Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:
Cash and Cash Equivalents - The carrying amount of cash and cash equivalents approximates fair value because of the short maturity of those instruments.
TODCO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Debt - The fair value of the Company’s third party debt, including capital lease obligations, is estimated based on the current rates offered to the Company for debt of the same remaining maturities. The fair value of the Company’s related party debt at December 31, 2004 was not practicable to determine due to the uncertainty of the timing of future repayments.
Note 9 - Other Current Liabilities
Other current liabilities are comprised of the following (in millions):
Note 10 - Impairment of Long-Lived Assets
In December 2004, the Company recorded a $2.8 million pre-tax impairment charge related to the planned decommissioning of the three lake barges in Venezuela which had ceased to be used as operational assets.
In the second quarter of 2003, the Company decided to remove five jackup rigs from drilling service and market the rigs for alternative uses such as production platforms or accommodation units. The Company does not anticipate returning the five rigs to drilling service as it would be cost prohibitive. As a result of this decision, the Company tested the carrying value of the rigs for impairment during the second quarter of 2003 and recorded a pre-tax $10.6 million non-cash impairment charge as a result of the impairment test.
As a result of the lack of success of the original business strategy of Energy Virtual Partners, Inc. and Energy Virtual Partners, LP, cost basis investments of the Company, the Company determined that the assets of those entities did not support the Company’s $1.0 million recorded investment and recorded a pre-tax $1.0 million non-cash impairment charge in the second quarter of 2003. The liquidation of these entities was completed in early 2004.
The impairment losses noted above have been included in the Company’s reportable segments results based on the segment of each of the assets impaired. See Note 17.
TODCO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 11 - Supplementary Cash Flow Information
Supplementary cash flow information relating to both continuing and discontinued operations is as follows (in millions):
(a)
In the first half of 2003, four subsidiaries, ownership interests in two majority-owned subsidiaries, a platform rig and certain other assets were sold or distributed to affiliated companies (see Note 20). The $103.9 million in cash held by subsidiaries at the time of the sales or distributions was reflected in financing activities in the consolidated statement of cash flows. The non-cash effect on the consolidated balance sheet was reflected as a decrease in accounts receivable-trade and other receivables of $21.4 million, a decrease in accounts receivable-related party of $298.8 million, an $8.3 million decrease in other current assets, a $752.2 million decrease in non-current assets related to discontinued operations, a $39.0 million decrease in other assets, a decrease in accounts payable trade and other current liabilities of $31.9 million, a decrease in accounts payable-related party of $108.4 million, a $15.5 million decrease in deferred taxes, a decrease in other long-term liabilities of $28.3 million, a decrease in notes payable of $88.0 million, a $524.7 million decrease in long-term debt-related party, a $98.2 million decrease in minority interest and a decrease in additional paid-in capital of $224.7 million.
(b)
Prior to the closing of the Company’s IPO in February 2004, the Company completed a non-cash exchange of $528.9 million in long-term related party notes payable to Transocean and related accrued interest payable for shares of the Company’s Class B common stock (see Notes 3 and 6).
(c)
In connection with the closing of the IPO, the Company completed certain equity transactions related to the Company’s separation from Transocean. In February 2004, the Company recorded business and tax indemnities of the Company by Transocean of $10.7 million as an increase in accounts receivable-related party and an increase in additional paid-in capital and transferred to Transocean $1.0 million of intercompany payable balances as of the IPO date as an increase in additional paid-in capital (see Note 3). Additionally, the Company recorded the book transfer of substantially all pre-IPO income tax benefits to Transocean of $181.4 million as a decrease in deferred income tax assets and a decrease in additional paid-in capital. In the first quarter of 2005, the Company recorded an additional $7.7 million in pre-IPO deferred state tax liabilities that existed at the IPO. This recognition resulted in a $7.7 million reduction in additional paid-in capital, $0.9 million of deferred state tax benefit and a $6.8 million increase in deferred tax liabilities (see Note 12).
(d)
In December 2003, Transocean contributed to the Company $84.7 million in net accounts payable-related party owed to Transocean.
TODCO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 12 - Income Taxes
Income tax expense (benefit) from continuing operations before minority interest and cumulative effect of a change in accounting principle consisted of the following (in millions):
The domestic and foreign components of income (loss) from continuing operations before income taxes, minority interest and cumulative effect of a change in accounting principle were as follows (in millions):
The effective tax rate, as computed on income (loss) from continuing operations before income taxes, minority interest and cumulative effect of a change in accounting principle differs from the statutory U.S. income tax rate due to the following:
TODCO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Deferred income taxes result from those transactions that affect financial and taxable income in different years. The nature of these transactions and the income tax effect of each were as follows (in millions):
Until the IPO in February 2004, the Company was a member of an affiliated group that included its parent company, Transocean Holdings, an affiliate of Transocean. Current and deferred taxes are allocated based upon what the Company’s tax provision (benefit) would have been had the Company filed a separate tax return for all periods presented.
Income taxes have been provided based upon the tax laws and rates in the countries in which operations are conducted and income is earned. Deferred tax assets and liabilities are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of the Company’s assets and liabilities using the applicable tax rates in effect. A valuation allowance for deferred tax assets is recorded when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized.
The $7.7 million increase in the valuation allowance during 2005 is due to foreign tax basis in excess of book basis caused by the relocation of certain of the Company’s rigs to new foreign locations, offset by utilization of post-IPO foreign net tax operating loss carryforwards (“NOLs”) and a decrease in the deferred tax assets related to Delta Towing. As of December 31, 2005, the valuation allowance primarily reflects an allowance against the foreign basis differences of $11.3 million, and the possible expiration of tax benefits associated with Delta Towing of $5.1 million and foreign NOLs totaling $2.3 million because, in the opinion of management, it is more likely than not that some or all of the benefits will not be realized.
There was no income tax effect on the cumulative effect of a change in accounting principle relating to the adoption of FIN 46 in 2003. See Note 2.
Recapitalizations of Reading & Bates Corporation (“R&B”) in 1989 and 1991, the merger of R&B and Falcon Drilling Company, Inc. in 1997, the Transocean Merger in 2001 and the “ownership change” that occurred following the Company’s secondary stock offering in September 2004, resulted in ownership changes for purposes of Section 382 of the Internal Revenue Code of 1986, as amended. As a result, the Company’s ability to utilize certain of its tax benefits is subject to an annual limitation. However, the Company believes that, in light of the amount of the annual limitation, it should not have a material effect on the Company’s ability to utilize its tax benefits for the foreseeable future. The amount of consolidated U.S. NOLs allocated to the Company and available
TODCO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
after consideration of the ownership change limitation was approximately $751 million as of December 31, 2005. These NOLs expire in the years 2018 through 2024. The amount of foreign NOLs available was approximately $14 million, of which approximately $7 million expire if not used between 2006 and 2015, and the remainder can be carried forward indefinitely.
Tax Sharing Agreement - In connection with the IPO, the Company entered into a tax sharing agreement with Transocean whereby the Company must pay Transocean for substantially all pre-IPO income tax benefits utilized or deemed to have been utilized subsequent to the closing of the IPO. In addition, the Company must also pay Transocean for any tax benefit resulting from the delivery by Transocean of its stock to an employee of TODCO in connection with the exercise of an employee stock option. In return, Transocean agreed to indemnify the Company against substantially all pre-IPO income tax liabilities.
Additionally, the tax sharing agreement provides that if any person other than Transocean or its subsidiaries becomes the beneficial owner of greater than 50% of the total voting power of the Company’s outstanding voting stock, the Company will be deemed to have utilized all of the pre-IPO tax benefits, and the Company will be required to pay Transocean an amount for the deemed utilization of these tax benefits adjusted by a specified discount factor. This payment is required even if the Company is unable to utilize the pre-IPO tax benefits.
Under the tax sharing agreement with Transocean, if the utilization of a pre-IPO tax benefit defers or precludes the Company’s utilization of any post-IPO tax benefit, its payment obligation with respect to the pre-IPO tax benefit generally will be deferred until the Company actually utilizes that post-IPO tax benefit. This payment deferral will not apply with respect to, and the Company will have to pay currently for the utilization of pre-IPO tax benefits to the extent of (a) up to 20% of any deferred or precluded post-IPO tax benefit arising out of the Company’s payment of foreign income taxes, and (b) 100% of any deferred or precluded post-IPO tax benefit arising out of a carryback from a subsequent year. Therefore, the Company may not realize the full economic value of tax deductions, credits and other tax benefits that arise post-IPO until it has utilized all of the pre-IPO tax benefits, if ever.
Upon consummation of the IPO, the Company recorded the tax sharing agreement to eliminate the valuation allowance associated with the pre-IPO tax benefits and reflect the associated liability to Transocean for the pre-IPO tax benefits as a corresponding obligation within the deferred income tax accounts. The net effect was a $181.4 million reduction in additional paid-in capital. In addition, the company recorded as a credit to additional paid-in capital $10.3 million for Transocean’s indemnification for pre-IPO liabilities that existed as of the IPO date with a corresponding offset to a related party receivable from Transocean.
During the first quarter of 2005, the Company recorded an additional $7.7 million in pre-IPO deferred state tax liabilities that existed at the IPO date. The recognition of these pre-IPO deferred state tax liabilities resulted in a $7.7 million reduction in additional paid-in capital, $0.9 million of deferred state tax benefit and a $6.8 million increase in deferred tax liabilities.
In September 2005, Transocean instructed TODCO, pursuant to a provision in the tax sharing agreement, to take a tax deduction for profits realized by current and former employees and directors of TODCO from the exercise of Transocean stock options during calendar 2004. Transocean also indicated that it expected TODCO to take a similar deduction in future years to the extent there were profits realized by its current and former employees and directors during those future periods.
It is TODCO’s belief that the tax sharing agreement only requires TODCO to pay Transocean for deductions related to stock option exercises by persons who were TODCO employees on the date of exercise. Transocean disagrees with TODCO’s interpretation of the tax sharing agreement as it relates to this issue and it believes that TODCO must pay for all stock option exercises, irrespective of whether any employment or other service provider relationship may have terminated prior to the exercise of the employee stock option. As such, Transocean initiated dispute resolution proceedings against TODCO.
TODCO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
TODCO recorded its obligation to Transocean based upon its interpretation of the tax sharing agreement. However, due to the uncertainty of the outcome of this dispute, TODCO established a reserve equal to the benefit derived from stock option deductions relating to persons who were not employees of TODCO on the date of the exercise. For the tax year ending December 31, 2004, the deduction related to all current and former employees and directors of TODCO was $8.8 million with only $1.1 million attributable to persons who were employees of TODCO on the date of exercise. Additionally, TODCO has been informed by Transocean that from January 1, 2005 to December 31, 2005, current and former employees and directors of TODCO have realized $85.3 million of gains from the exercise of Transocean stock options with $4.3 million relating to persons who were employees of TODCO on the date of exercise. If Transocean’s interpretation of the tax sharing agreement prevails, TODCO would recognize a tax benefit for former employee and director stock option exercises and pay Transocean 35% for the deduction. While this would not increase TODCO’s tax expense, it would defer utilization of pre-IPO income tax benefits.
During the years ended December 31, 2005 and 2004, the Company utilized pre-IPO income tax benefits to offset its current federal income tax obligation resulting in a liability to Transocean of $43.8 million and $7.6 million, respectively. Additionally, during the years ended December 31, 2005 and 2004, the Company utilized pre-IPO state tax benefits resulting in a liability to Transocean of $0.1 million and $0.8 million, respectively. The Company also utilized pre-IPO foreign tax benefits during 2005 resulting in a liability to Transocean of $1.0 million at December 31, 2005. There was no liability due to Transocean for the utilization of foreign tax benefits at December 31, 2004. As of December 31, 2005 and 2004, the Company estimates it owed Transocean $44.9 million and $8.4 million, respectively, for pre-IPO federal, state and foreign income tax benefits utilized.
As of December 31, 2005, the Company had approximately $282 million of estimated pre-IPO income tax benefits subject to the obligation to reimburse Transocean. If an acquisition of beneficial ownership had occurred on December 31, 2005, the estimated amount that the Company would have been required to pay Transocean would have been approximately $197 million, or 70% of the pre-IPO tax benefits at December 31, 2005.
The estimated liabilities to Transocean at December 31, 2005 and 2004 and the estimated amount of remaining pre-IPO income tax benefits subject to the obligation to reimburse Transocean at December 31, 2005 do not reflect the benefit of the tax deduction for stock option exercises of former employees who were not employees of TODCO on the date of the exercise and are presented within accrued income taxes - related party in the Company’s condensed consolidated balance sheets.
Note 13 - Commitments and Contingencies
Operating Leases - The Company has operating leases covering premises and equipment. Certain operating leases contain renewal options. Lease expense was $21.7 million, $13.6 million and $13.8 million for the three years ended December 31, 2005, respectively. As of December 31, 2005, future minimum lease payments relating to operating leases were as follows (in millions):
TODCO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Litigation. In October 2001, the Company was notified by the U.S. Environmental Protection Agency (“EPA”) that the EPA had identified a subsidiary of the Company as a potentially responsible party in connection with the Palmer Barge Line superfund site located in Port Arthur, Jefferson County, Texas. Based upon the information provided by the EPA and the Company’s review of its internal records to date, the Company disputes its designation as a potentially responsible party and does not expect that the ultimate outcome of this case will have a material adverse effect on its consolidated results of operations, financial position or cash flows. The Company continues to monitor this matter.
TODCO vs. Transocean Inc. and Transocean Holdings Inc. (“Transocean”). In connection with the Company’s separation from Transocean, the Company executed a tax sharing agreement with Transocean. The agreement provides that the Company must pay Transocean for certain pre-IPO tax benefits utilized or deemed to have been utilized subsequent to the IPO. The agreement alsoprovides that the Company must pay Transocean for any tax benefit resulting from the delivery by Transocean of its stock to an employee of the TODCO Tax Group that results in a tax benefit to the Company. In September 2005, Transocean instructed the Company to take a tax deduction for profits realized by the Company’s current and former employees and directors from the exercise of Transocean stock options during calendar 2004. Transocean also indicated that it expected the Company to take a similar deduction in future years to the extent there were profits realized by the Company’s current and former employees and directors during those future periods. The Company believes that the applicable provision of the agreement only requires the Company to pay Transocean for deductions related to stock option exercises by persons who were employees of the TODCO Tax Group on the date of exercise and has advised Transocean accordingly. Both parties have issued arbitration demand notices to the other and are in the process of attempting to select a neutral arbitrator to decide the dispute. In addition, the Company has filed a lawsuit against Transocean in Texas State District Court seeking to have the agreement overturned in its entirety. The dispute is in its earliest stages of development and it is difficult to predict the eventual outcome. In any event, the Company does not expect the outcome of this matter to have a material adverse effect on its consolidated results of operations, financial position or cash flows.
Robert E. Aaron et al. vs. Phillips 66 Company et al. Circuit Court, Second Judicial District, Jones County, Mississippi. This is the case name used to refer to several cases that have been filed in the Circuit Courts of the State of Mississippi involving 768 persons that allege personal injury arising out of asbestos exposure in the course of their employment by the defendants between 1965 and 2002. The complaints name as defendants, among others, certain of the Company’s subsidiaries and certain of Transocean’s subsidiaries to whom the Company may owe indemnity and other unaffiliated defendant companies, including companies that allegedly manufactured drilling related products containing asbestos that are the subject of the complaints. The number of unaffiliated defendant companies involved in each complaint ranges from approximately 20 to 70. The complaints allege that the defendant drilling contractors used 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. The trial court granted 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 served. In that regard, a majority of these cases have been assigned to a special master who has approved a form of questionnaire to be completed by plaintiffs so that claims made may be properly served against specific defendants. As of the date of this report, approximately 699 questionnaires had been submitted. Of those, approximately 103 shared periods of employment by TODCO and Transocean which could lead to claims against either company. The Company has not determined which entity would be responsible for such claims under the master separation agreement between the two companies. The Company has not yet had an opportunity to conduct any additional discovery to verify the number of plaintiffs, if any, that were employed by its subsidiaries or Transocean’s subsidiaries or otherwise have any connection with the Company’s or Transocean’s drilling operations. The Company intends to defend itself vigorously and, based on the
TODCO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
limited information available at this time, the Company does not expect the ultimate outcome of these lawsuits to have a material adverse effect on its consolidated results of operations, financial position or cash flows.
Under the master separation agreement, Transocean has agreed to indemnify the Company for any losses it incurs as a result of the legal proceedings described in the following two paragraphs. See Note 3.
In December 2002, the Company received an assessment for corporate income taxes from SENIAT, the national Venezuelan tax authority, of approximately $20.7 million (based on the current exchange rates at the time of the assessment and inclusive of penalties) relating to calendar years 1998 through 2000. In March 2003, the Company paid approximately $2.6 million of the assessment, plus approximately $0.3 million in interest, and the Company is contesting the remainder of the assessment. After the Company made the partial assessment payment, the Company received a revised assessment in September 2003 of approximately $16.7 million (based on the current exchange rates at the time of the assessment and inclusive of penalties). The Company does not expect the ultimate resolution of this assessment to have a material impact on its consolidated results of operations, financial condition or cash flows.
In 1984, in connection with the financing of the corporate headquarters, at that time, for Reading & Bates Corporation (“R&B”), a predecessor to one of the Company’s subsidiaries, in Tulsa, Oklahoma, the Greater Southwestern Funding Corporation (“Southwestern”) issued and sold, among other instruments, Zero Coupon Series B Bonds due 1999 through 2009 with an aggregate $189.0 million value at maturity. Paine Webber Incorporated purchased all of the Series B Bonds for resale and in 1985 acted as underwriter in the public offering of most of these bonds. The proceeds from the sale of the bonds were used to finance the acquisition and construction of the headquarters. R&B’s rental obligation was the primary source for repayment of the bonds. In connection with the offering, R&B entered into an indemnification agreement to indemnify Southwestern and Paine Webber from loss caused by any untrue statement or alleged untrue statement of a material fact or the omission or alleged omission of a material fact contained or required to be contained in the prospectus or registration statement relating to that offering. Several years after the offering, R&B defaulted on its lease obligations, which led to a default by Southwestern. Several holders of Series B bonds filed an action in Tulsa, Oklahoma in 1997 against several parties, including Paine Webber, alleging fraud and misrepresentation in connection with the sale of the bonds. In response to a demand from Paine Webber in connection with that lawsuit and a related lawsuit, R&B agreed in 1997 to retain counsel for Paine Webber with respect to only that part of the referenced cases relating to any alleged materialmisstatement or omission relating to R&B made in certain sections of the prospectus or registration statement. The agreement to retain counsel did not amend any rights and obligations under the indemnification agreement. There has been only limited progress on the substantive allegations in the case. The trial court has denied class certification, and the plaintiffs’ appeal of this denial to a higher court has been denied. The plaintiffs further appealed that decision and that appeal was denied. The case has now been dismissed.
The Company and its subsidiaries are involved in a number of other lawsuits, all of which have arisen in the ordinary course of the Company’s business. The Company does not believe that ultimate liability, if any, resulting from any such other pending litigation will have a material adverse effect on its business or consolidated financial position.
The Company cannot predict with certainty the outcome or effect of any of the litigation matters specifically described above or of any such other pending litigation. There can be no assurance that the Company’s belief or expectations as to the outcome or effect of any lawsuit or other litigation matter will prove correct and the eventual outcome of these matters could materially differ from management’s current estimates.
Surety Bonds - As is customary in the contract drilling business, the Company also has various surety bonds totaling $23.2 million in place as of December 31, 2005 that secure customs obligations and certain performance and other obligations. These bonds were issued primarily in connection with the Company’s contracts with PEMEX and Petroleos de Venezuela (“PDVSA”), the Venezuelan national oil company.
TODCO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Self-Insurance - The Company is at risk for the deductible portion of its insurance coverage. In the opinion of management, adequate accruals have been made based on known and estimated exposures up to the deductible portion of the Company’s insurance coverages.
Rig Reactivations - In anticipation of rig reactivations in 2006, the Company has placed orders for equipment with long lead times, including a $4.4 million commitment for three top-drives with an 18-month option for ten additional top-drive units and $12.9 million of drill pipe for delivery in 2006.
Note 14 - Stock-Based Compensation Plans
TODCO Long-Term Incentive Plan (the “2004 Plan”) - In February 2004, the Company adopted the 2004 Plan, a long-term incentive plan for certain employees and non-employee directors of the Company, in order to provide additional incentives and to increase the personal stake of participants in the continued success of the Company. The 2004 Plan provided for the grant of options to purchase shares of the Company’s Class A common stock, restricted stock, deferred stock units, share appreciation rights, cash awards, supplemental payments to cover tax liabilities associated with the aforementioned types of awards, and performance awards. Most awards under the 2004 Plan vest over a three-year period. A maximum of 3,000,000 shares of the Company’s Class A common stock were reserved for issuance under the Plan. In May 2005, the stockholders approved the TODCO 2005 Long-Term Incentive Plan and no further awards will be granted under the 2004 Plan.
TODCO 2005 Long-Term Incentive Plan (the “2005 Plan”) - The 2005 Plan was adopted to continue to provide employees, non-employee directors and consultants to the Company with additional incentives and increase their personal stake in the success of the Company. The 2005 Plan provides for the grant of options to purchase shares of the Company’s Class A common stock, restricted stock, deferred performance units, deferred stock units, share appreciation rights, cash awards, supplemental payments to cover tax liabilities associated with the aforementioned types of awards and performance awards. The number of shares reserved under the 2005 Plan and available for incentive awards is 4,000,000 shares of the Company’s Class A common stock. Additionally, any grants or awards under the 2004 Plan that expire or are forfeited, terminated or otherwise cancelled or that are settled in cash in lieu of shares are reserved and available for incentive awards under the 2005 Plan. Any incentive awards other than stock options under the 2005 Plan reduce the shares available for grant by two shares for every one share granted. At December 31, 2005, there were 3,951,518 shares remaining available for the grant of awards under the 2005 Plan.
Stock Options - The following tables summarize information about TODCO stock options held by employees and non-employee directors of the Company at December 31, 2005:
TODCO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The fair value of the options granted under the 2004 Plan and the 2005 Plan was estimated using the Black-Scholes options pricing model with the following weighted average assumptions:
In 2004, the Company granted 730,000 options with immediate vesting provisions and 705,000 options with two year vesting terms. All other stock options granted by the Company have three year vesting terms. All options granted by the Company have a ten-year contractual life.
During 2005, the Company received $17.8 million in stock option proceeds of which $4.3 million was the result of the tax benefits recognized as a result of the exercise of the options. The Company recognized compensation expense of $3.9 million and $8.7 million related to stock options granted under the plans during the years ended December 31, 2005 and 2004, respectively. There was no compensation expense related to the Company’s stock options for the year ended December 31, 2003.
Restricted Stock Awards - During 2005 and 2004, the Company granted 168,488 and 314,175 shares of restricted stock, respectively. The weighted average fair value of restricted stock granted in 2005 and 2004 was $21.26 and $14.40, respectively. For restricted stock awards, at the date of grant, the recipient has substantially all the rights of a stockholder, subject to certain restrictions on transferability and a risk of forfeiture. Although restricted stock awards typically vest over a three year period beginning at the date of grant, there were 156,496 of the restricted stock awards granted in conjunction with the IPO which vested in July 2005. The Company records unearned compensation in stockholders’ equity equal to the market value of the restricted stock awards on the date of grant and charges the unearned compensation to expense over the vesting period. During the years ended December 31, 2005 and 2004, the Company recognized compensation expense of $2.5 million and $1.9 million, respectively, related to restricted stock awards. There was no compensation expense related to restricted stock awards for the year ended December 31, 2003.
Deferred Stock Awards - The Company granted 27,148 shares of deferred stock to members of the Company’s Board of Directors. During 2005, 2,858 shares of the deferred stock awards were issued which resulted in 24,290 shares outstanding as of December 31, 2005. The weighted average fair value of deferred stock awards granted in 2005 was $24.05. Although the deferred stock awards vest immediately upon grant, they are not issued until certain requirements are met, typically five years of service or separation from service as a member of the Board of Directors. Since the deferred stock awards vest immediately, the compensation expense associated with the awards is recorded in the month granted. During the year ended December 31, 2005, the Company recognized compensation expense of $0.7 million related to deferred stock awards. There was no compensation expense related to these awards for the years ended December 31, 2004 and 2003.
Deferred Performance Units - During 2005, the Company granted 173,481 shares of deferred performance units to various employees of the Company. The weighted average fair value of the deferred performance units granted in 2005 was $10.10. The total maximum number of the deferred performance units earned and awarded from the total number of shares granted is based upon the level of achievement by the Company of a predetermined performance standard over a three-year period commencing on January 1st of the year granted. During the year ended December 31, 2005, the Company recognized compensation expense of $0.5 million related to deferred performance units. There was no compensation expense related to these awards for the years ended December 31, 2004 and 2003.
TODCO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Transocean Stock Options - Prior to the IPO, certain of the Company’s employees were awarded stock options under the Transocean incentive plan. The Company accounted for these plans under APB 25 under which no compensation expense was recognized for options granted with an exercise price at or above the market price of Transocean’s common stock. See Note 2.
During 2003, in connection with the transfer of the Transocean Assets to Transocean, certain of the Company’s employees not associated with the Company’s Shallow Water business became employees of Transocean, and Transocean assumed any future expense relating to the vesting of the options held by these employees. Additionally, certain former Transocean employees became employees of the Company. The Company assumed any future expense relating to the vesting of options held by these former Transocean employees. In connection with the IPO, the employees holding these Transocean stock options were treated as terminated for the convenience of Transocean on the IPO date. As a result, the 250,797 options outstanding on February 10, 2004 became fully vested and were modified to remain exercisable over the original contractual life. In connection with the modification of these options, the Company recognized $1.5 million of additional compensation expense in the first quarter of 2004. No further compensation expense will be recorded in the future related to the Transocean options.
Note 15 - Retirement Plans and Other Post employment Benefits
The Company has a defined contribution savings plan (the “Savings Plan”) that is established for the benefit of eligible employees of the Company and complies with Section 401(k) of the Internal Revenue Code. The Savings Plan allows employees to contribute up to 15 percent of their base salary (subject to certain limitations). Under the Savings Plan, the Company makes matching contributions to equal 100 percent of employee contributions on the first six percent of each employee’s base salary. Participants direct the investment of their accumulated contributions into various plan investment options.
Compensation costs under the plans amounted to $2.8 million, $2.4 million and $2.6 million for the years ended December 31, 2005, 2004 and 2003, respectively.
Note 16 - Related Party Transactions
Allocation of Administrative Costs - Subsidiaries of Transocean provided certain administrative support to the Company prior to and immediately after the IPO. Transocean charged the Company a proportional share of its administrative costs based on estimates of the percentage of work the individual Transocean departments performed for the Company. In the opinion of management, Transocean charged the Company for all costs incurred on its behalf under a comprehensive and reasonable cost allocation method. The amount of expense allocated to the Company for the three years ended December 31, 2005 was $0.0 million, $0.4 million and $1.4 million, respectively. These allocated expenses were classified as general and administrative expense - related party.
Transfer of Transocean Assets - The Company sold and/or distributed 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. See Note 20.
Note 17 - Segments, Geographical Analysis and Major Customers
The Company’s operating assets consist of jackup and submersible drilling rigs and inland drilling barges located in the U.S. Gulf of Mexico, two jackup rigs and a land rig in Trinidad, two jackup drilling rigs and one platform rig in Mexico, a jackup drilling rig in Angola, one jackup drilling rig in Colombia, and land drilling units located in Venezuela. The Company provides contract oil and gas drilling services and reports the results of those operations in four business segments which correspond to the principal geographic regions in which the Company operates: U.S. Gulf of Mexico Segment, U.S. Inland Barge Segment, Other International Segment and Delta Towing Segment. The accounting policies of the reportable segments are the same as those described in Note 2.
TODCO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Revenue, depreciation, impairment loss, operating income (loss) and identifiable assets by reportable business segment were as follows (in millions):
(a)
Includes general and administrative expenses and impairment charges which were not allocated to a reportable segment. Identifiable assets include assets related to discontinued operations of $0.1 million at December 31, 2003.
The Company provides contract oil and gas drilling services with different types of drilling equipment in several countries. Geographic information about the Company’s operations was as follows (in millions):
A substantial portion of the Company’s assets are mobile. Asset locations at the end of the period are not necessarily indicative of the geographic distribution of the earnings generated by such assets during the periods.
TODCO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Capital expenditures during the year ended December 31, 2005 by segment were $5.8 million for the U.S. Gulf of Mexico Segment, $12.1 million for the U.S. Inland Barge Segment, $3.4 million for the Other International Segment, $0.1 million for the Delta Towing Segment and $1.0 million for Corporate and Other.
The Company’s international operations are subject to certain political and other uncertainties, including risks of war and civil disturbances (or other events that disrupt markets), expropriation of equipment, repatriation of income or capital, taxation policies, and the general hazards associated with certain areas in which operations are conducted.
The Company provides drilling rigs, related equipment and work crews primarily on a dayrate basis to customers who are drilling oil and gas wells. The Company provides these services mostly to independent oil and gas companies, but it also services major international and government-controlled oil and gas companies. In 2004 and 2003, one customer, Applied Drilling Technologies, Inc., accounted for 11 percent of the Company’s total operating revenue for each respective year. No other customer accounted for 10 percent or more of the Company’s total operating revenues in 2004 or 2003. No customer accounted for 10% or greater of the Company’s operating revenues in 2005. However, the loss of any significant customer could have a material adverse effect on the Company’s results of operations.
Note 18 - Income (Loss) Per Common Share
The following table sets forth the computation of basic and diluted earnings per share for the years ended December 31, 2005, 2004 and 2003:
As a result of the net loss reported for the year ended December 31, 2004, the following potential common shares have been excluded from the calculation of diluted loss per share because their effect would be anti-dilutive: 71,595 potential common shares related to outstanding stock options and 112,667 potential common shares related to restricted stock awards. There were no common stock equivalents outstanding during December 31, 2003. No adjustments to net income (loss) were made in calculating diluted earnings (loss) per share for the three years ended December 31, 2005.
TODCO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Note 19 - Quarterly Results (Unaudited)
Summarized quarterly financial data for the years ended December 31, 2005 and 2004 are as follows (in millions, except per share amounts):
(a)
Fourth quarter of 2004 includes a $2.8 million impairment loss on long-lived assets and a $1.8 million gain resulting from the Company’s reassessment of estimated medical claims incurred but not yet paid.
(b)
The sum of EPS for the four quarters may differ from the annual EPS due to the required method of computing weighted average number of shares in the respective periods.
Note 20 - Discontinued Operations
There were no revenues related to discontinued operations for the years ended December 31, 2004 or 2005. Operating revenues related to discontinued operations for the year ended December 31, 2003 was $53.4 million.
At December 31, 2005 and December 31, 2004 liabilities related to discontinued operations consisted primarily of other current liabilities of $0.2 million. At December 31, 2003, net liabilities related to discontinued operations consisted of other current receivables of $0.1 million and accounts payable and other current liabilities of $0.5 million.
Transfer of Transocean Assets - During 2003, the Company substantially completed the transfer of all Transocean Assets, including the transfers of all revenue-producing Transocean Assets, to Transocean primarily as in-kind dividends and transfers in exchange for the cancellation of debt payable to Transocean, and, in some instances, for cash. The following is a summary of these transactions executed during 2003.
In-Kind Distributions:
•
During 2003, two subsidiaries of the Company with an aggregate net book value of $44.6 million were distributed as in-kind dividends for no consideration to Transocean. The transactions were recorded as decreases to additional paid-in capital.
•
Certain accounts receivable balances from related parties, a 12.5 percent undivided interest in an aircraft and other miscellaneous Transocean Assets with an aggregate net book value of $203.3 million were distributed to Transocean as in-kind dividends for no consideration in 2003. The transactions were recorded as decreases to additional paid-in capital.
TODCO
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Sales:
•
The Company sold to Transocean the stock of Arcade Drilling AS for net proceeds of $264.1 million and recorded a net pre-tax loss of $11.0 million in 2003. The sales transaction was at fair value based on an independent third party appraisal and is included in the results of discontinued operations. In consideration for the sale of the subsidiary, Transocean cancelled $233.3 million principal amount of the Company’s 6.95% Exchanged Notes. The market value attributable to the notes, 113.21 percent of the principal amount, was based on an independent third party appraisal. The Company recorded a net pre-tax loss of approximately $30.0 million in 2003 related to the retirement of these notes. (See Note 6.)
•
The Company sold Cliffs Platform Rig 1 to Transocean in consideration for the cancellation of $13.9 million of the 6.95% Exchanged Notes held by Transocean. The Company recorded the excess of the sales price over the net book value of $1.6 million as an increase to additional paid-in capital and a pre-tax loss on the retirement of debt of $1.5 million in 2003. (See Note 6.)
•
In 2003, the Company sold to Transocean its 50 percent interest in Deepwater Drilling L.L.C. and its 60 percent interest in Deepwater Drilling II L.L.C. in consideration for the cancellation of $43.7 million principal amount of the Company’s debt held by Transocean. The value of the Company’s interests in these subsidiaries was determined based on a similar third party transaction. The Company recorded the excess of the sales price over the net book value of the membership interests of $21.6 million as an increase to additional paid-in capital.
•
In 2003, the Company sold to Transocean its membership interests in its wholly-owned subsidiary, R&B Falcon Drilling (International & Deepwater) Inc. LLC. As consideration for the stock sold, Transocean cancelled $238.8 million of the Company’s outstanding debt held by them. The sales transaction was based on a valuation, which took into account valuations of the drilling units owned by the entities sold to Transocean. The Company recorded the excess of the net book value over the sales price of the membership interests of $60.9 million as a loss on sale of assets, which was included in the results of discontinued operations and a pre-tax loss on the retirement of debt of $48.0 million. (See Note 6).
Assignments:
•
In 2003, the Company assigned to Transocean the drilling contract for the drilling unit Deepwater Frontier for no consideration.
Note 21 - Subsequent Events
In January 2006, the Company purchased Chouest’s 75% interest in Delta Towing for one dollar and paid $1.1 million to retire Delta Towing’s $2.9 million related party note to Chouest. As a result of the consolidation of Delta Towing in the Company’s consolidated financial statements in accordance with FIN 46 beginning December 31, 2003, the purchase of the additional interest in Delta Towing is not expected to have a material impact on the consolidated results of operations, financial position or cash flows. See Note 4.
TODCO AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(a)
Uncollectible accounts receivable written off, net of recoveries.
(b)
Balance attributable to consolidation of Delta Towing at December 31, 2003.
Other schedules have been omitted either because they are not required or are not applicable, or because the required information is included in the consolidated financial statements or notes thereto.
Item 9.
Item 9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A.
Controls and Procedures
As of December 31, 2005, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective. Disclosure controls and procedures are controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.
There have been no changes in our internal control over financial reporting that occurred during the three months ended December 31, 2005 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management’s Report on Responsibility for Internal Control over Financial Reporting
Management is responsible for establishing and maintaining an adequate system of internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. The company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. The company’s internal control over financial reporting includes those policies and procedures that:
i.
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company;
ii.
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorization of management and directors of the company; and
iii.
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisitions, use or disposition of the company’s assets that could have a material effect on the financial statements.
Internal control over financial reporting has certain inherent limitations which may not prevent or detect misstatements. In addition, changes in conditions and business practices may cause variation in the effectiveness of internal controls.
Management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2005, based on criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on its assessment and those criteria, management concluded that the company maintained effective internal control over financial reporting as of December 31, 2005.
Management’s assessment of the effectiveness of the company’s internal control over financial reporting as of December 31, 2005 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report presented on page 52 of this Form 10-K.
Item 9B.
Item 9B.
Other Information
None.
PART III
Item 10.
Item 10.
Directors and Executive Officers of the Registrant
Item 11.
Item 11.
Executive Compensation
Item 12.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13.
Item 13.
Certain Relationships and Related Transactions
Item 14.
Item 14.
Principal Accounting Fees and Services
The information required by Items 10, 11, 12, 13 and 14 is incorporated herein by reference to the Company’s definitive proxy statement for its 2005 annual general meeting of stockholders, which will be filed with the Securities and Exchange Commission pursuant to Regulation 14A under the Securities Act of 1934 within 120 days of December 31, 2005.
PART IV
Item 15.
Item 15.
Exhibits and Financial Statement Schedules
a.
Financial Statements and Financial Statement Schedule
Financial Statements - See Index to Consolidated Financial Statements and Schedule on Page 49.
Financial Statement Schedule - See Index to Consolidated Financial Statements and Schedule on Page 49.
Exhibit Index
*
Management compensation contract, plan or arrangement.

Furnished, not filed, in accordance with Item 601(b)(32) of Registration S-K.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized in Houston, Texas, on this 28th day of February, 2006.
TODCO
/s/ JAN RASK
Jan Rask
President and Chief Executive Officer
Pursuant to the requirements of the Securities Act of 1934, this report has been signed by the following persons in the capacities indicated on the 28th day of February, 2006.
*
Signed through power of attorney
Exhibit Index
*
Management compensation contract, plan or arrangement.

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