-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, EXfqC8KmeR0SdOIq31XTNpMhhcQu1HlOVcYrbiJc9Mvp0IOrSKiMnk8+/Q7SCG8j Nej4V5vnW/IpJXdBUZa7Sg== 0000008411-06-000156.txt : 20061213 0000008411-06-000156.hdr.sgml : 20061213 20061213165245 ACCESSION NUMBER: 0000008411-06-000156 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 9 CONFORMED PERIOD OF REPORT: 20060930 FILED AS OF DATE: 20061213 DATE AS OF CHANGE: 20061213 FILER: COMPANY DATA: COMPANY CONFORMED NAME: ATWOOD OCEANICS INC CENTRAL INDEX KEY: 0000008411 STANDARD INDUSTRIAL CLASSIFICATION: DRILLING OIL & GAS WELLS [1381] IRS NUMBER: 741611874 STATE OF INCORPORATION: TX FISCAL YEAR END: 0930 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-13167 FILM NUMBER: 061274673 BUSINESS ADDRESS: STREET 1: 15835 PARK TEN PL DR STREET 2: SUITE 200 CITY: HOUSTON STATE: TX ZIP: 77084 BUSINESS PHONE: 2817497845 MAIL ADDRESS: STREET 1: 15835 PARK TEN PL DR STREET 2: SUITE 200 CITY: HOUSTON STATE: TX ZIP: 77084 10-K 1 form10k.txt ================================================================================ SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 Form 10-K ANNUAL REPORT UNDER SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2006 COMMISSION FILE NUMBER 1-13167 ATWOOD OCEANICS, INC. (Exact name of registrant as specified in its charter) TEXAS 74-1611874 (State or other jurisdiction of (I.R.S. Employer Identification No.) incorporation or organization) 15835 Park Ten Place Drive 77084 Houston, Texas (Zip Code) (Address of principal executive offices) Registrant's telephone number, including area code: 281-749-7800 Securities registered pursuant to Section 12(b) of the Act: Common Stock, $1 par value New York Stock Exchange Preferred Stock Purchase Rights New York Stock Exchange (Title of each Class) (Name of each exchange on which registered) Securities registered pursuant to Section 12(g) of the Act: NONE Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [X] No [ ] Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes [ ] No [X] Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filings requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation in S-K (ss.229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K [ ]. Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of "accelerated filer" and "large accelerated filer" in Rule 12b-2 of the Exchange Act. (Check One): Large accelerated filer[X] Accelerated filer[ ] Non-accelerated filer[ ] Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes [ ] No [X] The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which our Common Stock, $1 par value was last sold, or the average bid and asked price of such Common Stock, as of March 31, 2006 was $1,566,000,000. The number of shares outstanding of our Common Stock, $1 par value, as of December 12, 2006: 31,068,013. DOCUMENTS INCORPORATED BY REFERENCE (1) Annual Report to Shareholders for the fiscal year ended September 30, 2006 - Referenced in Parts I, II and IV of this report. (2) Proxy Statement for Annual Meeting of Shareholders to be held February 8, 2007 - Referenced in Part III of this report. =============================================================================== PART I ITEM 1. BUSINESS Atwood Oceanics, Inc. (which together with its subsidiaries is identified as the "Company," "we" or "our," unless the context requires otherwise) is engaged in the international offshore drilling and completion of exploratory and developmental oil and gas wells and related support, management and consulting services. We are headquartered in Houston, Texas, USA. Atwood Oceanics, Inc. was organized in 1968 as a corporation and commenced operations in 1970. During our thirty-nine year history, the majority of our drilling units have operated outside of United States waters, and we have conducted drilling operations in most of the major offshore exploration areas of the world. Our current worldwide operations include eight premium offshore mobile drilling units located in five regions of the world - offshore Southeast Asia, offshore Africa, offshore Australia, the Black Sea and the U.S. Gulf of Mexico. We also manage two modern, self-contained platform rigs. Approximately 93%, 93%, and 94% of our contract revenues were derived from foreign operations in fiscal years 2006, 2005 and 2004, respectively. The submersible RICHMOND is our only drilling unit currently working in United States waters. We support our operations from our Houston headquarters and offices currently located in Australia, Malaysia, Egypt, Malta, Indonesia, West Africa, Singapore and the United Kingdom. For information relating to the contract revenues, operating income and identifiable assets attributable to specific geographic areas of operations, see Note 13 of Notes to Consolidated Financial Statements contained in our Annual Report to Shareholders for fiscal year 2006, incorporated by reference herein. The following table presents our wholly-owned and operating rig fleet as of December 12, 2006: Water Depth Rig Name Rig Type Upgraded Rating (feet) --------- -------- -------- ------------ ATWOOD EAGLE Semisubmersible 2000/2002 5,000 ATWOOD HUNTER Semisubmersible 1997/2001 5,000 ATWOOD FALCON Semisubmersible 1998/2006 5,000 ATWOOD SOUTHERN CROSS Semisubmersible 1997/2006 2,000 SEAHAWK Semisubmersible 1992/1999/2006 600 Tender Assist ATWOOD BEACON Jack-up 2003(1) 400 VICKSBURG Jack-up 1998 300 RICHMOND Submersible 2000/2002 70 (1) The ATWOOD BEACON was constructed in 2003. When necessary, we update and upgrade our fleet in order to maintain premium, modern equipment. In fiscal year 1997, we commenced an internal upgrade program of all of our active drilling units. Collectively, since fiscal year 1997, we have invested approximately $400 million in upgrading seven offshore mobile drilling units in connection with our upgrade program. In August 2003, our eighth drilling unit, the ATWOOD BEACON, an ultra-premium, jack-up rig, commenced its initial drilling contract following completion of its construction and commissioning in early August 2003. This drilling unit was constructed on time and on budget at a cost of approximately $120 million. We have a ninth drilling unit, the ATWOOD AURORA, another ultra-premium, jack-up, under construction at Brownsville, Texas, with scheduled delivery on or before September 2008. The total construction cost of this drilling unit (including capitalized interest) is expected to be approximately $160 million. All of our currently active drilling units have contractual dayrate commitments that are the highest in their respective histories. Currently, we have approximately 95% and 80% of our available rig days contracted for fiscal years 2007 and 2008, respectively. For many years, one of our strategic focuses has been maintaining high equipment utilization. We had a 100% and 98% equipment utilization rate in fiscal years 2006 and 2005, respectively and have averaged over 90% utilization over the last ten years. Today, virtually all worldwide offshore drilling areas have strong market fundamentals, with high utilization of both floating as well as bottom supported drilling units. Despite the increase in operating costs for fiscal year 2006, our operating results significantly increased for fiscal year 2006 compared to fiscal year 2005. Although we anticipate a continuing trend for increases in operating costs during the next fiscal year, with our backlog of contracted days providing increasing revenue expectations, we anticipate that revenues, operating cash flows and earnings for fiscal years 2007 and 2008 will reflect a significant improvement over fiscal year 2006 operating results, and they are expected to be the highest in our history. 2 OFFSHORE DRILLING EQUIPMENT In addition to our owned and operating rigs described above, we also manage two modern, self-contained platform rigs; thus, giving us a current diversified fleet of ten (10) drilling rigs. Each type of drilling rig is uniquely designed for different purposes and applications, for operations in different water depths, bottom conditions, environments and geographical areas, and for different drilling and operating requirements. The following descriptions of the various types of drilling rigs we own or manage illustrate the diversified range of applications of our rig fleet. Semisubmersible Rigs. Each semisubmersible drilling unit has two hulls, the lower of which is capable of being flooded. Drilling equipment is mounted on the main hull. After the drilling unit is towed to location, the lower hull is flooded, lowering the entire drilling unit to its operating draft, and the drilling unit is anchored in place. On completion of operations, the lower hull is deballasted, raising the entire drilling unit to its towing draft. This type of drilling unit is designed to operate in greater water depths than a jack-up and in more severe sea conditions than other types of drilling units. Semisubmersible units are generally more expensive to operate than jack-up drilling rigs and are often limited in the amount of supplies that can be stored on board. Semisubmersible Tender Assist Rigs. Semisubmersible tender assist rigs operate like a semisubmersible except that their drilling equipment is temporarily installed on permanently constructed offshore support platforms. Semisubmersible rigs provide crew accommodations, storage facilities and other support for drilling operations. Jack-up Drilling Rigs. A jack-up drilling rig contains all of the drilling equipment on a single hull designed to be towed to a well site. Once on location, legs are lowered to the sea floor and the unit is raised out of the water by jacking the hull up the legs. On completion of the well, the unit is jacked down, and towed to the next location. A jack-up drilling rig can operate in more severe sea and weather conditions than a drillship and is less expensive to operate than a semisubmersible. However, because it must rest on the sea floor, a jack-up cannot operate in water as deep as that in which a semisubmersible unit can operate. A jack-up drilling rig is a bottom supported rig. Submersible Drilling Rigs. The submersible drilling rig we own has two hulls, the lower being a mat, which is capable of being flooded. Drilling equipment and crew accommodations are located on the main hull. After the drilling unit is towed to its location, the lower hull is flooded, lowering the entire unit to its operating draft at which it rests on the sea floor. On completion of operations, the lower hull is deballasted, raising the entire unit to its towing draft. This type of drilling unit is designed to operate in shallow water depths ranging from 9 to 70 feet and can operate in moderately severe sea conditions. Although drilling units of this type are less expensive to operate, like a jack-up drilling rig, they cannot operate in water as deep as that in which a semisubmersible rig can operate. A submersible drilling rig is a bottom supported unit. Modular Platform Rigs. A modular platform rig is similar to a land rig in its basic components. Modular platform rigs are temporarily installed on permanently constructed offshore support platforms in order to perform drilling operations. After the drilling phase is completed, the modular rig is broken down into convenient packages and moved by workboats. A platform rig usually stays at a location for several months, if not years, since several wells are typically drilled from a support platform. DRILLING CONTRACTS We obtain the contracts under which we operate our vessels either through individual negotiation with the customer or by submitting proposals in competition with other contractors. Our contracts vary in their terms and conditions. The initial term of contracts for our owned and/or managed vessels has ranged from the length of time necessary to drill one well to several years and is generally subject to early termination in the event of a total loss of the drilling vessel, a force majeure event, excessive equipment breakdown or failure to meet minimum performance criteria. It is not unusual for contracts to contain renewal provisions, which in time of weak market conditions are usually at the option of the customer; while in time of strong market demand, like today, are usually mutually agreeable. The rate of compensation specified in each contract depends on the nature of the operation to be performed, the duration of the work, the amount and type of equipment and services provided, the geographic areas involved, market conditions and other variables. Generally, contracts for drilling, management and support services specify a basic rate of compensation computed on a dayrate basis. Such agreements generally provide for a reduced dayrate payable when operations are interrupted by equipment failure and subsequent repairs, field moves, adverse weather conditions or other factors beyond our control. 3 Some contracts also provide for revision of the specified dayrates in the event of material changes in certain items of cost. Any period during which a vessel is not earning a full operating dayrate because of the above conditions or because the vessel is idle and not on contract will have an adverse effect on operating profits. An over-supply of drilling rigs in any market area can adversely affect our ability to employ our drilling vessels. Our active rig utilization, which excludes contractual downtime for rigs upgraded, for fiscal years 2006, 2005 and 2004 was 100%, 98% and 93%, respectively. Of our current drilling contracts, seven of our drilling units have contract terms that extend beyond fiscal year 2007. The ATWOOD EAGLE's contract in Australia extends into fiscal year 2010. The ATWOOD FALCON, ATWOOD BEACON and VICKSBURG contracts extend into fiscal year 2009. The ATWOOD HUNTER, ATWOOD SOUTHERN CROSS, and SEAHAWK contracts extend into fiscal year 2008. Even though the RICHMOND currently does not have a contract commitment that extends beyond fiscal year 2007, we expect that this rig will remain highly utilized under the current market conditions. With the completion of the ATWOOD FALCON's water depth upgrade and the reattachment of the last leg sections on the ATWOOD BEACON in November 2006, we currently have no planned shipyard time for any of our rigs for the remainder of fiscal year 2007. Currently, the only planned downtime for the remainder of fiscal year 2007 is a ten to fourteen day required inspection planned for the ATWOOD HUNTER. However, we can provide no assurance that we will not experience some unplanned idle time on our other drilling units during fiscal year 2007. Maintaining high equipment utilization in up, as well as down, cycles is a key factor in generating cash to satisfy current and future obligations. For long moves of drilling equipment, we attempt to obtain from our customers either a lump sum or a dayrate as mobilization compensation for expenses incurred during the period in transit. In today's strong market environment, we are able to receive a dayrate as mobilization compensation; however, a surplus of certain types of units, either worldwide or in particular operating areas, can result in our acceptance of a contract which provides only partial or no recovery of relocation costs. Additionally, under such a contract, we may not make any profit during the relocation of a rig. For example, in fiscal year 2003, the ATWOOD EAGLE was moved from offshore Greece to offshore Angola at a cost of $8.2 million, with only $2.7 million received in mobilization compensation, and the ATWOOD FALCON was relocated from offshore Australia with mobilization costs of approximately $2 million, which approximated mobilization compensation. We can give no assurance that we will receive full or partial recovery of any future relocation costs beyond that for which we have already contracted. Operation of our drilling equipment is subject to the offshore drilling requirements of petroleum exploration companies and agencies of foreign governments. These requirements are, in turn, subject to fluctuations in government policies, world demand and prices for petroleum products, proved reserves in relation to such demand and the extent to which such demand can be met from onshore sources. We also contract to provide various types of services to third party owners of drilling rigs. These contracts are normally for a stated term or until termination of operations or stages of operation at a particular facility or location. The services may include, as in the case of contracts we have entered into in connection with operations offshore Australia, the supply of personnel and rig design, fabrication, installation and operation. The contracts normally provide for reimbursement to us for all out-of-pocket expenses, plus a service or management fee for all of the services performed. In most instances, the amount charged for the services may be adjusted if there are changes in conditions, scope or costs of operations. We generally obtain insurance or a contractual indemnity from the owner for liabilities which could be incurred in operations. The majority of our contracts are denominated in United States dollars, but occasionally a portion of a contract is payable in local currency. To the extent there is a local currency component in a contract, we attempt to match revenue in the local currency to operating costs paid in the local currency such as local labor, shore base expenses, and local taxes, if any. INSURANCE AND RISK MANAGEMENT Our operations are subject to the usual hazards associated with the drilling of oil and gas wells, such as blowouts, explosions and fires. In addition, our equipment is subject to various risks particular to our industry which we seek to mitigate by maintaining insurance. These risks include leg damage to jack-ups during positioning (such as we experienced in fiscal year 2004 with the ATWOOD BEACON), capsizing, grounding, collision and damage from severe weather conditions. Any of these risks could result in damage or destruction of drilling rigs and oil and gas wells, personal injury and property damage, suspension of operations or environmental damage through oil spillage or extensive, uncontrolled fires. Therefore, in addition to general business insurance policies, we maintain the following insurance relating to our rigs and rig operations: hull and machinery, loss of hire, builder's risk, cargo, war risks, protection and indemnity, and excess liability, among others. 4 Our operations are also subject to disruption due to terrorism. As a result of significant losses incurred by the insurance industry due to terrorism, offshore drilling rig accidents, damages from hurricanes and other events, we have experienced increases in premiums for certain insurance coverages. Although we believe that we are adequately insured against normal and foreseeable risks in our operations in accordance with industry standards, such insurance may not be adequate to protect us against liability from all consequences of well disasters, marine perils, extensive fire damage, damage to the environment or disruption due to terrorism. To date, we have not experienced difficulty in obtaining insurance coverage, although we can provide no assurance as to the future availability of such insurance or the cost thereof. The occurrence of a significant event against which we are not adequately insured could have a material adverse effect on our financial position. See also "Risk Factors" in Item 1A. CUSTOMERS During fiscal year 2006, we performed operations for 13 customers. Because of the relatively limited number of customers for which we can operate at any given time, revenues from four different customers amounted to 10% or more of our revenues in fiscal year 2006 as indicated below: Customer Percentage of Revenues ---------------------------------------------------------- Woodside Energy Ltd. 28% Burullus Gas Co. 14% Sarawak Shell 12% Hoang Long and Hoan Vu Companies 12% Our business operations are subject to the risks associated with a business having a limited number of customers for our products or services, and a decrease in the drilling programs of these customers in the areas where we are employed may adversely affect our revenues and therefore, our results of operations and cash flows. COMPETITION We compete with several international offshore drilling contractors, most of which are substantially larger than we are and which possess appreciably greater financial and other resources. The offshore drilling industry is very competitive, with no single offshore drilling contractor being dominant. Thus, there is competition in securing available offshore drilling contracts. Price competition is generally the most important factor in the offshore drilling industry; however, when there is high worldwide utilization of equipment, as currently exists, rig availability and suitability become more important factors in securing contracts than price. The technical capability of specialized drilling equipment and personnel at the time and place required by customers are also important. Other competitive factors include work force experience, rig suitability, efficiency, condition of equipment, safety performance, reputation and customer relations. We believe that we compete favorably with respect to these factors. INDUSTRY TRENDS The performance of the offshore drilling industry is largely determined by basic supply and demand for available equipment. Periods of high demand and high dayrates are often followed by periods of low demand and low dayrates. Offshore drilling contractors can mobilize rigs from one region of the world to another, can "cold stack" rigs (taking them out of service) or reactivate cold stacked rigs in order to adjust supply of existing equipment in various markets to meet demand. The market is highly cyclical and is typically driven by general economic activity and changes in actual or anticipated oil and gas prices. Generally, sustained high energy prices translate into increased exploration and production spending by oil and gas companies, which in turn results in increased drilling activity and demand for equipment like ours. The offshore markets where we currently operate, offshore Southeast Asia, offshore Africa, offshore Australia, the Black Sea, and shallow water U.S. Gulf of Mexico, offer the potential for continuing high utilization and dayrates. We expect demand for all of our drilling units to continue to be strong due to demand for oil and gas in their respective regions, as well as significant growth in demand for oil and gas driven by China's and India's rapidly expanding economies. INTERNATIONAL OPERATIONS The large majority of our operations are in foreign jurisdictions which we have historically found to be more stable in market terms. We believe international operations provide a better opportunity than domestic operations 5 for attractive contracts and returns over the longer term. Since 1970, we have operated offshore Southeast Asia, offshore Australia, in the Far East, in the Mediterranean Sea, in the Arabian Gulf, in the Red Sea, in the Black Sea, offshore India, offshore Papua New Guinea, offshore Vietnam, offshore East and West Africa, offshore Central and South America, offshore China and in the U.S. Gulf of Mexico. Currently, we have only one rig working in the U.S. Gulf of Mexico. We have foreign offices currently located in Australia, Malaysia, Egypt, Malta, Indonesia, West Africa, Singapore and the United Kingdom. Virtually all of our tax provision for fiscal years 2004, 2005 and 2006 relates to taxes in foreign jurisdictions. As a result of working in foreign jurisdictions, we earned a high level of operating income in certain nontaxable and deemed profit tax jurisdictions which significantly reduced our effective tax rate for the current fiscal year when compared to the United States statutory rate. In addition, we reversed a $1.8 million tax contingent liability during fiscal year 2006 due to the expiration of the statute of limitations in a foreign jurisdiction. Also, we were advised by a foreign tax authority that it had approved acceptance of certain amended prior year tax returns. The acceptance of these amended tax returns, along with the fiscal year 2005 tax return for this foreign jurisdiction, resulted in the recognition of a $4.6 million tax benefit in the third quarter of the current fiscal year. Including the two previously mentioned discrete items, which reduced our rate by 7%, our effective tax rate for fiscal year 2006 was approximately 6%. During fiscal year 2005, our tax provision was offset by two foreign discrete items. During the first quarter of fiscal year 2005, we received a $1.7 million tax refund in Malaysia related to a previously reserved tax receivable. In addition, a $1.0 million deferred tax benefit was recognized in June 2005 due to the filing and subsequent acceptance by the local tax authority, of amended prior year tax returns. In addition, on December 1, 2005, we received notification from the United States Department of Treasury that a previously reserved United States income tax refund we had been pursuing for over two years had been approved for payment. Based upon this approval, we reduced our income tax provision by the refund amount of $3.3 million for the year ended September 30, 2005. Furthermore, during fiscal year 2005, operating income earned in certain nontaxable and deemed profit tax jurisdictions was higher when compared to fiscal year 2004, including business interruption proceeds earned by the ATWOOD BEACON in a zero tax jurisdiction for approximately three and a half months, which contributed to a lower effective tax rate. As a result of these items, our effective tax rate for fiscal year 2005 was significantly less when compared to fiscal year 2004 and the United States statutory rate. Excluding any discrete items that may occur, we expect our effective tax rate to be approximately 15-20% for fiscal year 2007 due to increased earnings in foreign jurisdictions with high statutory tax rates. We do not record federal income taxes on the undistributed earnings of our foreign subsidiaries that we consider to be permanently reinvested in foreign operations. In addition, there was no cumulative amount of such undistributed earnings and profits at September 30, 2006. EMPLOYEES We currently employ approximately 1,100 persons in our domestic and foreign operations. In connection with our foreign drilling operations, we are often required by the host country to hire substantial portions of our work force in that country and, in some cases, these employees are represented by foreign unions. To date, we have experienced little difficulty in complying with such requirements, and our drilling operations have not been significantly interrupted by strikes or work stoppages. Our success depends to a significant extent upon the efforts and ability of our executive officers and other key management personnel. There is no assurance that these individuals will continue in such capacity for any particular period of time. ENVIRONMENTAL REGULATION The transition zone and shallow water areas of the U.S. Gulf of Mexico are ecologically sensitive. Environmental issues have led to higher drilling costs, a more difficult and lengthy well permitting process and, in general, have adversely affected decisions of oil and gas companies to drill in these areas. In the United States, regulations applicable to our operations include regulations controlling the discharge of materials into the environment, requiring removal and cleanup of materials that may harm the environment or otherwise relating to the protection of the environment. For example, as an operator of a mobile offshore drilling unit in navigable United States waters and some offshore areas, we may be liable for damages and costs incurred in connection with oil spills or other unauthorized discharges of chemicals or wastes resulting from or related to those operations. Laws and regulations protecting the environment have become more stringent, and may in some cases impose strict liability, rendering a person liable for environmental damage without regard to negligence or fault on the part of such person. Some of these laws and regulations may expose us to liability for the conduct of or conditions caused by others or for acts which were in compliance with all applicable laws at the time they were performed. The application of these requirements or the adoption of new requirements could have a material adverse effect on our financial position, results of operations or cash flows. 6 The U.S. Federal Water Pollution Control Act of 1972, commonly referred to as the Clean Water Act, prohibits the discharge of specified substances into the navigable waters of the United States without a permit. The regulations implementing the Clean Water Act require permits to be obtained by an operator before specified exploration activities occur. Offshore facilities must also prepare plans addressing spill prevention control and countermeasures. Violations of monitoring, reporting and permitting requirements can result in the imposition of civil and criminal penalties. The U.S. Oil Pollution Act of 1990, or OPA, and related regulations impose a variety of requirement on "responsible parties" related to the prevention of oils spills and liability for damages resulting from such spills. Few defenses exist to the liability imposed by OPA, and the liability could be substantial. Failure to comply with ongoing requirements or inadequate cooperation in the event of a spill could subject a responsible party to civil or criminal enforcement action. We have taken all steps necessary to comply with this law, and have received a Certificate of Financial Responsibility (Water Pollution) from the U.S. Coast Guard. Our operations in United States waters are also subject to various other environmental regulations regarding pollution, and we have taken steps to ensure compliance with those regulations. The U.S. Outer Continental Shelf Lands Act authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the outer continental shelf. Included among these are regulations that require the preparation of spill contingency plans and establish air quality standards for certain pollutants, including particulate matter, volatile organic compounds, sulfur dioxide, carbon monoxide and nitrogen oxides. Specific design and operational standards may apply to outer continental shelf vessels, rigs, platforms, vehicles and structures. Violations of lease conditions or regulations related to the environment issued pursuant to the U.S. Outer Continental Shelf Lands Act can result in substantial civil and criminal penalties, as well as potential court injunctions curtailing operations and cancelling leases. Such enforcement liabilities can result from either governmental or citizen prosecution. The U.S. Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, also known as the "Superfund" law, imposes liability without regard to fault or the legality of the original conduct on some classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. Such persons include the owner or operator of a facility where a release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at a particular site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the cost of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. It is also not uncommon for third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. OTHER GOVERNMENTAL REGULATION Our non-United States contract drilling operations are subject to various laws and regulations in the countries in which we operate, including laws and regulations relating to the importation of and operation of drilling units, currency conversions and repatriation, oil and gas exploration and development, taxation of offshore earnings and earnings of expatriate personnel, the use of local employees and suppliers by foreign contractors and duties on the importation and exportation of drilling units and other equipment. Governments in some foreign countries have become increasingly active in regulating and controlling the ownership of concessions and companies holding concessions, the exploration for oil and gas and other aspects of the oil and gas industries in their countries. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by major oil and gas companies and may continue to do so. Operations in less developed countries can be subject to legal systems that are not as mature or predictable as those in more developed countries, which can lead to greater uncertainty in legal matters and proceedings. Our worldwide operations are also subject to a variety of laws and regulations designed to improve safety in the businesses in which we operate. International conventions, including Safety of Life at Sea, also referred to as SOLAS, and the Code for Construction of Mobile Offshore Drilling Units, also referred to as the MODU CODE, generally are applicable to our offshore operations. Historically, we have made significant capital expenditures and incurred additional expenses to ensure that our equipment complies with applicable local and international health and safety regulations. Our future efforts to comply with these regulations and standards may increase our costs and may affect the demand for our services by influencing energy prices or limiting the areas in which we may drill. Although significant capital expenditures may be required to comply with these governmental laws and regulations, such compliance has not, to date, materially adversely affected our earnings, cash flows or competitive position. 7 SECURITIES LITIGATION SAFE HARBOR STATEMENT Statements included in this report which are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions related thereto) are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. In addition, we and our representatives may from to time to time make other oral or written statements which are also forward-looking statements. These forward-looking statements are made based upon management's current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements. Important factors that could cause our actual results of operations, financial condition or cash flows to differ include, but are not necessarily limited to: o our dependence on the oil and gas industry; o the operational risks involved in drilling for oil and gas; o changes in rig utilization and dayrates in response to the level of activity in the oil and gas industry, which is significantly affected by indications and expectations regarding the level and volatility of oil and gas prices, which in turn are affected by such things as political, economic and weather conditions affecting or potentially affecting regional or worldwide demand for oil and gas, actions or anticipated actions by OPEC, inventory levels, deliverability constraints, and future market activity; o the extent to which customers and potential customers continue to pursue deepwater drilling; o exploration success or lack of exploration success by our customers and potential customers; o the highly competitive and cyclical nature of our business, with periods of low demand and excess rig availability; o the impact of the war with Iraq or other military operations, terrorist acts or embargoes elsewhere; o our ability to enter into and the terms of future drilling contracts; o the availability of qualified personnel; o our failure to retain the business of one or more significant customers; o the termination or renegotiation of contracts by customers; o the availability of adequate insurance at a reasonable cost; o the occurrence of an uninsured loss; o the risks of international operations, including possible economic, political, social or monetary instability, and compliance with foreign laws; o the effect public health concerns could have on our international operations and financial results; o compliance with or breach of environmental laws; o the incurrence of secured debt or additional unsecured indebtedness or other obligations by us or our subsidiaries; o the adequacy of sources of liquidity; 8 o currently unknown rig repair needs and/or additional opportunities to accelerate planned maintenance expenditures due to presently unanticipated rig downtime; o higher than anticipated accruals for performance-based compensation due to better than anticipated performance by us, higher than anticipated severance expenses due to unanticipated employee terminations, higher than anticipated legal and accounting fees due to unanticipated financing or other corporate transactions, and other factors that could increase general and administrative expenses; o the actions of our competitors in the offshore drilling industry, which could significantly influence rig dayrates and utilization; o changes in the geographic areas in which our customers plan to operate, which in turn could change our expected effective tax rate; o changes in oil and gas drilling technology or in our competitors' drilling rig fleets that could make our drilling rigs less competitive or require major capital investments to keep them competitive; o rig availability; o the effects and uncertainties of legal and administrative proceedings and other contingencies; o the impact of governmental laws and regulations and the uncertainties involved in their administration, particularly in some foreign jurisdictions; o changes in accepted interpretations of accounting guidelines and other accounting pronouncements and tax laws; o the risks involved in the construction, upgrade, and repair of our drilling units; and o such other factors as may be discussed in this report and our other reports filed with the Securities and Exchange Commission, or SEC. These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on future results. The words "believe," "impact," "intend," "estimate," "anticipate," "plan" and similar expressions identify forward-looking statements. These forward-looking statements are found at various places throughout the Management's Discussion and Analysis in our Annual Report to Shareholders for fiscal year 2006 incorporated by reference in Part II and elsewhere in this report. When considering any forward-looking statement, you should also keep in mind the risk factors described in other reports or filings we make with the SEC from time to time. Undue reliance should not be placed on these forward-looking statements, which are applicable only on the date hereof. Neither we nor our representatives have a general obligation to revise or update these forward-looking statements to reflect events or circumstances that arise after the date hereof or to reflect the occurrence of unanticipated events. COMPANY INFORMATION We file annual, quarterly and current reports, proxy statements and other information with the SEC. Our SEC filings are available to the public over the internet at the SEC's web site at www.sec.gov. Our website address is www.atwd.com. We make available free of charge on or through our website our annual report on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. We have adopted a code of ethics applicable to our chief executive officer and our senior financial officers which is also available on our website. We intend to satisfy the disclosure requirement regarding any changes in or waivers from our code of ethics by posting such information on our website or by filing a Form 8-K for such event. Unless stated otherwise, information on our website is not incorporated by reference into this report or made a part hereof for any purpose. You may also read and copy any document we file at the SEC's Public Reference Room at 100F Street NE, Washington, DC 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference rooms and copy charges. 9 ITEM 1A. RISK FACTORS An investment in our securities involves significant risks. You should carefully consider the risk factors described below before deciding whether to invest in our securities. The risks and uncertainties described below are not the only ones we face. You should also carefully read and consider all of the information we have included, or incorporated by reference, in this report for Form 10-K before you decide to invest in our securities. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also impair our business. WE RELY ON THE OIL AND NATURAL GAS INDUSTRY AND VOLATILE OIL AND NATURAL GAS PRICES IMPACT DEMAND FOR OUR SERVICES. Demand for our services depends on activity in offshore oil and natural gas exploration, development and production. The level of exploration, development and production activity is affected by factors such as: o prevailing oil and natural gas prices; o expectations about future prices; o the cost of exploring for, producing and delivering oil and natural gas; o the sale and expiration dates of available offshore leases; o worldwide demand for petroleum products; o current availability of oil and natural gas resources; o the rate of discovery of new oil and natural gas reserves in offshore areas; o local and international political and economic conditions; o technological advances; o ability of oil and natural gas companies to generate or otherwise obtain funds for capital; o the ability of the Organization of Petroleum Exporting Countries, or OPEC, to set and maintain production levels and pricing; o political or other disruptions that limit exploration, development and production in oil-producing countries; o the level of production by non-OPEC countries; and o laws and governmental regulations that restrict exploration and development of oil and natural gas in various jurisdictions. During recent years, the level of offshore exploration, development and production activity has been volatile. Such volatility is likely to continue in the future. A decline in the worldwide demand for oil and natural gas or prolonged low oil or natural gas prices in the future would likely result in reduced exploration and development of offshore areas and a decline in the demand for our services. Even during periods of high prices for oil and natural gas, companies exploring for oil and gas may cancel or curtail programs, or reduce their levels of capital expenditures for exploration and production for a variety of reasons. Any such decrease in activity is likely to reduce our day rates and our utilization rates and, therefore, could have a material adverse effect on our financial condition, results of operations and cash flows. RIG CONVERSIONS, UPGRADES OR NEWBUILDS MAY BE SUBJECT TO DELAYS AND COST OVERRUNS. From time to time we may undertake to increase our fleet capacity through conversions or upgrades to rigs or through new construction. These projects are subject to risks of delay or cost overruns inherent in any large construction project resulting from numerous factors, including the following: 10 o shortages of equipment, materials or skilled labor; o unscheduled delays in the delivery of ordered materials and equipment; o unanticipated cost increases; o weather interferences; o difficulties in obtaining necessary permits or in meeting permit conditions; o design and engineering problems; and o shipyard failures. OPERATING HAZARDS INCREASE OUR RISK OF LIABILITY; WE MAY NOT BE ABLE TO FULLY INSURE AGAINST THESE RISKS. Our operations are subject to various operating hazards and risks, including: o catastrophic marine disaster; o adverse sea and weather conditions; o mechanical failure; o navigation errors; o collision; o oil and hazardous substance spills, containment and clean up; o labor shortages and strikes; o damage to and loss of drilling rigs and production facilities; and o war, sabotage and terrorism. These risks present a threat to the safety of personnel and to our rigs, cargo, equipment under tow and other property, as well as the environment. We could be required to suspend our operations or request that others suspend their operations as a result of these hazards. Third parties may have significant claims against us for damages due to personal injury, death, property damage, pollution and loss of business if such event were to occur in our operations. We maintain insurance coverage against the casualty and liability risks listed above. We believe our insurance is adequate, and we have never experienced a loss in excess of policy limits. However, we may not be able to renew or maintain our existing insurance coverage at commercially reasonable rates or at all. Additionally, there is no assurance that our insurance coverage will be adequate to cover future claims that may arise. THE INTENSE PRICE COMPETITION AND CYCLICALITY OF OUR INDUSTRY, WHICH IS MARKED BY PERIODS OF LOW DEMAND, EXCESS RIG AVAILABILITY AND LOW DAYRATES, COULD HAVE AN ADVERSE EFFECT ON OUR REVENUES, PROFITABILITY AND CASH FLOWS. The contract drilling business is highly competitive with numerous industry participants. The industry has experienced consolidation in recent years and may experience additional consolidation. Recent mergers among oil and natural gas exploration and production companies have reduced the number of available customers. Drilling contracts are, for the most part, awarded on a competitive bid basis. Price competition is often the primary factor in determining which qualified contractor is awarded a job, although rig availability and the quality and technical capability of service and equipment are also factors. We compete with approximately ten other drilling contractors, most of which are substantially larger and have appreciably greater resources than us. 11 The industry in which we operate historically has been cyclical, marked by periods of low demand, excess rig supply and low dayrates, followed by periods of high demand, short rig supply and increasing dayrates. Periods of excess rig supply intensify the competition in the industry and often result in rigs being idled. Several markets in which we operate are currently oversupplied. Lower utilization and dayrates in one or more of the regions in which we operate would adversely affect our revenues and profitability. Prolonged periods of low utilization and dayrates could also result in the recognition of impairment charges on certain of our drilling rigs if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these rigs may not be recoverable. We may be required to idle rigs or to enter into lower-rate contracts in response to market conditions in the future. WE RELY HEAVILY ON A SMALL NUMBER OF CUSTOMERS AND THE LOSS OF A SIGNIFICANT CUSTOMER COULD HAVE AN ADVERSE IMPACT ON OUR FINANCIAL RESULTS. Our contract drilling business is subject to the usual risks associated with having a limited number of customers for our services. Woodside Energy Ltd., Burullus Gas Co., Sarawak Shell and Hoang Long and Hoan Vu Companies provided approximately 28%, 14%, 12% and 12%, respectively of our consolidated revenues in fiscal year 2006. Our results of operations could be materially adversely affected if any of our major customers terminate its contracts with us, fails to renew our existing contracts or refuses to award new contracts to us. WE MAY SUFFER LOSSES IF OUR CUSTOMERS TERMINATE OR SEEK TO RENEGOTIATE THEIR CONTRACTS. Certain of our contracts with customers may be cancelable upon specified notice at the option of the customer. Other contracts require the customer to pay a specified early termination payment upon cancellation, which payments may not fully compensate us for the loss of the contract. Contracts customarily provide for either automatic termination or termination at the option of the customer in the event of total loss of the drilling rig or if drilling operations are suspended for extended periods of time by reason of acts of God or excessive rig downtime for repairs, or other specified conditions. Early termination of a contract may result in a rig being idle for an extended period of time. Our revenues may be adversely affected by customers' early termination of contracts, especially if we are unable to recontract the affected rig within a short period of time. During depressed market conditions, a customer may no longer need a rig that is currently under contract or may be able to obtain a comparable rig at a lower daily rate. As a result, customers may seek to renegotiate the terms of their existing drilling contracts or avoid their obligations under those contracts. The renegotiation of a number of our drilling contracts could adversely affect our financial position, results of operations and cash flows. WE ARE SUBJECT TO OPERATING RISKS SUCH AS BLOWOUTS AND WELL FIRES THAT COULD RESULT IN ENVIRONMENTAL DAMAGE, PROPERTY LOSS, AND PERSONAL INJURY OR DEATH. Our drilling operations are subject to many hazards that could increase the likelihood of accidents. Accidents can result in: o costly delays or cancellations of drilling operations; o serious damage to, or destruction of, equipment; o personal injury or death; o significant impairment of producing wells or underground geological formations; and o major environmental damage. Our offshore drilling operations are also subject to marine hazards, either at offshore sites or while drilling equipment is under tow, such as vessel capsizings, collisions or groundings. In addition, raising and lowering jack-up drilling rigs and offshore drilling platforms whose three legs independently penetrate the ocean floor, flooding semisubmersible ballast tanks to help fix the floating drilling unit over the well site and drilling into high-pressure formations are complex, hazardous activities and we can encounter problems. We have had accidents in the past due to some of the hazards described above, including the fiscal year 2004 ATWOOD BEACON incident. Because of the ongoing hazards associated with our operations: o we may experience a higher number of accidents in the future than expected; 12 o our insurance coverage may prove inadequate to cover losses that are greater than anticipated; o our insurance deductibles may increase; or o our insurance premiums may increase to the point where maintaining our current level of coverage is prohibitively expensive. Any similar events could yield future operating losses and have a significant adverse impact on our business. OUR RESULTS OF OPERATIONS WILL BE ADVERSELY AFFECTED IF WE ARE UNABLE TO SECURE CONTRACTS FOR OUR DRILLING RIGS ON ECONOMICALLY FAVORABLE TERMS. The drilling markets in which we compete frequently experience significant fluctuations in the demand for drilling services, as measured by the level of exploration and development expenditures, and the supply of capable drilling equipment. In response to fluctuating market conditions, we can, as we have done in the past, relocate drilling rigs from one geographic area to another, but only when such moves are economically justified. If demand for our rigs declines, rig utilization and dayrates are generally adversely affected. FAILURE TO OBTAIN AND RETAIN KEY PERSONNEL COULD IMPEDE OUR OPERATIONS. We depend to a significant extent upon the efforts and abilities of our executive officers and other key management personnel. There is no assurance that these individuals will continue in such capacity for any particular period of time. The loss of the services of one or more of our executive officers or key management personnel could adversely affect our operations. GOVERNMENT REGULATION AND ENVIRONMENTAL RISKS REDUCE OUR BUSINESS OPPORTUNITIES AND INCREASE OUR COSTS. We must comply with extensive government regulation in the form of international conventions, federal, state and local laws and regulations in jurisdictions where our vessels operate and are registered. These conventions, laws and regulations govern oil spills and matters of environmental protection, worker health and safety, and the manning, construction and operation of vessels, and vessel and port security. We believe that we are in material compliance with all applicable environmental, health and safety, and vessel and port security laws and regulations. We are not a party to any pending governmental litigation or similar proceeding, and we are not aware of any threatened governmental litigation or proceeding which, if adversely determined, would have a material adverse effect on our financial condition or results of operations. However, the risks of incurring substantial compliance costs, liabilities and penalties for non-compliance are inherent in our industry. Compliance with environmental, health and safety, and vessel and port security laws increases our costs of doing business. Additionally, environmental, health and safety, and vessel and port security laws change frequently. Therefore, we are unable to predict the future costs or other future impact of environmental, health and safety, and vessel and port security laws on our operations. There is no assurance that we can avoid significant costs, liabilities and penalties imposed as a result of governmental regulation in the future. OUR RELIANCE ON FOREIGN OPERATIONS EXPOSES US TO ADDITIONAL RISKS NOT GENERALLY ASSOCIATED WITH DOMESTIC OPERATIONS, WHICH COULD HAVE AN ADVERSE EFFECT ON OUR OPERATIONS OR FINANCIAL RESULTS. During the past five years, we derived substantially all of our revenues from foreign sources. We, therefore, face risks inherent in conducting business internationally, such as: o legal and governmental regulatory requirements; o difficulties and costs of staffing and managing international operations; o language and cultural differences; o potential vessel seizure or nationalization of assets; o import-export quotas or other trade barriers; 13 o renegotiation or nullification of existing contracts; o difficulties in collecting accounts receivable and longer collection periods; o foreign and domestic monetary policies; o political and economic instability; o terrorist acts, war and civil disturbances; o assault on property or personnel; o travel limitations or operational problems caused by severe acute respiratory syndrome (SARS) or other public health threats; o imposition of currency exchange controls; and o potentially adverse tax consequences, including those due to changes in laws or interpretation of existing laws. In the past, these conditions or events have not materially affected our operations. However, we cannot predict whether any such conditions or events might develop in the future. Also, we organized our subsidiary structure and our operations, in part, based on certain assumptions about various foreign and domestic tax laws, currency exchange requirements, and capital repatriation laws. While we believe our assumptions are correct, there can be no assurance that taxing or other authorities will reach the same conclusion. If our assumptions are incorrect, or if the relevant countries change or modify such laws or the current interpretation of such laws, we may suffer adverse tax and financial consequences, including the reduction of cash flow available to meet required debt service and other obligations. Any of these factors could materially adversely affect our international operations and, consequently, our business, operating results and financial condition. WE MAY SUFFER LOSSES AS A RESULT OF FOREIGN EXCHANGE RESTRICTIONS AND FOREIGN CURRENCY FLUCTUATIONS. A significant portion of the contract revenues of our foreign operations are paid in United States dollars; however, some payments are made in foreign currencies. As a result, we are exposed to currency fluctuations and exchange rate risks as a result of our foreign operations. To minimize the financial impact of these risks when we are paid in foreign currency, we attempt to match the currency of operating costs with the currency of contract revenue. However, any increase in the value of the United States dollar in relation to the value of applicable foreign currencies could adversely affect our operating revenues when translated into United States dollars. To date, currency fluctuations have not had a material impact on our financial condition or results of operations. WE ARE SUBJECT TO WAR, SABOTAGE AND TERRORISM, WHICH COULD HAVE AN ADVERSE EFFECT ON OUR BUSINESS. The terrorist attacks of September 11, 2001 have had a continuing impact, including those related to the current United States military campaigns in Afghanistan and Iraq, on the energy industry. It is unclear what impact the current United States military campaigns or possible future campaigns will have on the energy industry in general, or us in particular, in the future. Uncertainty surrounding retaliatory military strikes or a sustained military campaign may affect our operations in unpredictable ways, including changes in the insurance markets, disruptions of fuel supplies and markets, particularly oil, and the possibility that infrastructure facilities, including pipelines, production facilities, refineries, electric generation, transmission and distribution facilities, could be direct targets of, or indirect casualties of, an act of terror. War or risk of war may also have an adverse effect on the economy. The terrorist attacks have resulted in a hardening of the insurance market. We maintain insurance coverage against casualty and liability risks and have renewed our primary insurance program for the insurance year 2006-2007. We will evaluate the need to maintain this coverage as it applies to our drilling fleet in the future. We believe our insurance is adequate, and we have never experienced a loss in excess of policy limits. There is no assurance that our insurance coverage will be available or affordable and, if available, whether it will be adequate to cover future claims that may arise. 14 Instability in the financial markets as a result of war, sabotage or terrorism could also affect our ability to raise capital and could also adversely affect the oil, gas and power industries and restrict their future growth. OUR SIGNIFICANT DEBT LEVEL MAY HINDER OUR OPERATIONAL FLEXIBILITY AND MAKE IT DIFFICULT TO MEET OUR DEBT SERVICE OBLIGATIONS. We have significant indebtedness and will require substantial cash flow to meet our debt service requirements. At September 30, 2006, our long-term debt was $64 million. A high level of indebtedness will affect our future operations in several ways, including the following: o We may be more vulnerable to general adverse economic and industry conditions than some of our competitors who have less debt, and therefore, we may be at a competitive disadvantage. o Covenants in our debt obligations require us to meet certain financial tests and limit our ability to borrow additional funds, make certain capital expenditures, sell assets, pay cash dividends, or repurchase any of our outstanding common stock. o We may experience difficulties in obtaining additional financing in the future for working capital, capital expenditures, acquisitions or general corporate purposes. Our ability to meet our debt obligations will depend on our future performance, which will be affected by a range of economic, competitive, and business factors. We cannot control many of these factors, such as general economic and financial conditions in the oil and gas industry, the economy at large and competitive initiatives of our competitors. Our future cash flows may be insufficient to meet all of our debt obligations and commitments, and any insufficiency could negatively impact our business. To the extent that we are unable to repay our indebtedness as it becomes due or at maturity with cash on hand or from other sources, we will need to refinance our debt, sell assets or repay the debt with the proceeds of an equity offering. There is no assurance that additional indebtedness or equity financing will be available to us in the future for the refinancing or repayment of existing indebtedness, nor can we give any assurance as to the timing of any asset sales or the proceeds that could be realized by us from any such asset sale. THE SUBSTANTIAL EQUITY INTEREST OWNED BY CERTAIN SHAREHOLDERS MAY LIMIT THE ABILITY OF OTHER SHAREHOLDERS TO INFLUENCE THE OUTCOME OF DIRECTOR ELECTIONS AND OTHER MATTERS REQUIRING SHAREHOLDER APPROVAL. As of December 12, 2006, Helmerich & Payne International Drilling Co., owns of record and beneficially 4,000,000 shares, or approximately 13% of the issued and outstanding shares of our common stock. One of our directors, Hans Helmerich is an executive officer of Helmerich & Payne, Inc, ("H&P") the parent company of Helmerich & Payne International Drilling Co. Another director, George Dotson, was also an executive officer of H&P up until his retirement in 2006. The beneficial ownership of our common stock and membership of an officer of H&P on our board enables H&P to exercise some influence over the election of directors and other corporate matters requiring shareholder or board of directors' approval. FUTURE SALES OF OUR COMMON STOCK BY HELMERICH & PAYNE INTERNATIONAL DRILLING CO. COULD ADVERSELY AFFECT OUR MARKET PRICE. Helmerich & Payne International Drilling Co. has advised us that, consistent with its pursuit of a strategy of focusing on its core drilling business, it intends to evaluate its entire investment portfolio, which includes shares of our common stock, and its cash requirements on a continuous basis and that it may seek to dispose of all or a portion of the shares of our common stock owned by it when and as necessary, from time to time, to fund its corporate needs. Until the sale of all of the shares of common stock owned by Helmerich & Payne International Drilling Co. which are currently registered on Form S-3, Registration No. 333-117534, are sold or are de-registered, we will or may have a large number of shares of common stock outstanding and available for resale beginning at various points in the future. Sales of a substantial number of shares of our common stock in the public market, or the possibility that these sales may occur, could also make it more difficult for us to sell our common stock or other equity securities in the future at a time and at a price that we deem appropriate. ANTI-TAKEOVER PROVISIONS IN OUR AMENDED AND RESTATED CERTIFICATE OF FORMATION, SECOND AMENDED AND RESTATED BYLAWS, AND RIGHTS PLAN COULD MAKE IT DIFFICULT FOR HOLDERS OF OUR COMMON STOCK TO RECEIVE A PREMIUM FOR THEIR SHARES UPON A CHANGE OF CONTROL. 15 Holders of the common stock of acquisition targets often receive a premium for their shares upon a change of control. Texas law and the following provisions, among others, of our certificate of formation, bylaws and rights plan could have the effect of delaying or preventing a change of control and could prevent holders of our common stock from receiving such a premium: o We are subject to a provision of Texas corporate law that prohibits us from engaging in a business combination with any shareholder for three years from the date that person became an affiliated shareholder by beneficially owning 20% or more of our outstanding common stock, unless specified conditions are met. o Special meetings of shareholders may not be called by anyone other than our chairman of the board of directors, president, or the holders of at least one-tenth of all shares issued, outstanding, and entitled to vote. o Our board of directors has the authority to issue up to 1,000,000 shares of "blank-check" preferred stock and to determine the voting rights and other privileges of these shares without any vote or action by our shareholders. o We have issued "poison pill" rights to purchase Series A Junior Participating Preferred Stock under our rights plan, whereby the ownership of our shares by a potential acquirer can be significantly diluted by the sale at a significant discount of additional shares of our common stock to all other shareholders, which could discourage unsolicited acquisition proposals. ITEM 1B. UNRESOLVED STAFF COMMENTS None. ITEM 2. PROPERTIES Information regarding the current location and general character of our principal assets may be found in the table with the caption heading "Offshore Drilling Operations" in the Company's Annual Report to Shareholders for fiscal year 2006, which is incorporated by reference herein. 16 Collectively since fiscal year 1997, we have expended $386 million in upgrading seven offshore mobile drilling units. The timing and costs of the various upgrades are as follows: YEAR UPGRADE DRILLING UNITS COMPLETED COST OF UPGRADE -------------------------------- ------------- -------------- (In Millions) ATWOOD HUNTER (PHASE I) 1997 $ 40 ATWOOD SOUTHERN CROSS (PHASE I) 1997 35 ATWOOD FALCON (PHASE I) 1998 45 VICKSBURG 1998 35 SEAHAWK (PHASE I) 1999 22 ATWOOD EAGLE (PHASE I) 2000 8 RICHMOND 2000 7 ATWOOD HUNTER (PHASE II) 2001 58 ATWOOD EAGLE (PHASE II) 2002 90 ATWOOD SOUTHERN CROSS (PHASE II) 2006 7 SEAHAWK (PHASE II) 2006 16 ATWOOD FALCON (PHASE II) 2006 23 ---- $386 ==== In August 2003, our eighth active drilling unit, the newbuild ultra-premium jack-up, ATWOOD BEACON, commenced its initial drilling contract following completion of construction and commissioning. This drilling unit was constructed at a cost of approximately $120 million. On July 25, 2004, all three of the ATWOOD BEACON'S legs and its derrick were damaged while the rig was being positioned. The rigs and its legs were transported to the builder's shipyard in Singapore for inspection and initial repairs which were completed in January 2005. The remainder of the repairs were completed in November 2006. For more information concerning these costs, see Note 4 in Consolidated Financial Statements contained in our Annual Report to Shareholders for fiscal year 2006, incorporated by reference herein. The ATWOOD AURORA, another ultra-premium jack-up will become our ninth drilling unit upon expected completion of its construction on or before September 2008. This drilling unit is expected to have a total construction cost of approximately $160 million. In October 2005, we sold our semisubmersible hull, SEASCOUT, that we had purchased in 2000, for $10 million (net after certain expenses), which resulted in a gain of approximately $1 million. We purchased this hull for a possible upgrade to a tender assist vessel, but we never identified an acceptable contract opportunity. Also, in October 2005, we sold our spare 15,000 P.S.I. BOP stack for approximately $15 million, which resulted in an after tax gain of approximately $9 million. We completed this stack in 2003 for a possible future contractual requirement; however, the stack had never been utilized and we had no current contractual requirements for its use. At September 30, 2006, the collateral for our credit facility consisted primarily of preferred mortgages held by our senior lender covering all eight of our active drilling units. ITEM 3. LEGAL PROCEEDINGS We are party to a number of lawsuits which are ordinary, routine litigation incidental to our business, the outcome of which, individually, or in the aggregate, is not expected to have a material adverse effect on our financial condition, results of operations or cash flows. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SHAREHOLDERS During the fourth quarter of fiscal year 2006, no matters were submitted to a vote of shareholders through the solicitation of proxies or otherwise. PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SHAREHOLDER MATTERS As of December 12, 2006 there were approximately 3,300 beneficial owners of our common stock based upon information provided to us by a third party service provider. Our common stock is traded on the New York Stock Exchange. 17 We did not pay cash dividends in fiscal years 2005 or 2006 and we do not anticipate paying cash dividends in the foreseeable future because of the capital-intensive nature of our business. To enable us to maintain our high competitive profile in the industry, we expect to utilize cash reserves at the appropriate time to upgrade existing equipment or to acquire additional equipment. Our credit facility prohibits payment of cash dividends on common stock without lender approval. We did declare a two-for-one stock split of our common stock effected in the form of a 100% common stock dividend in March 2006. Market information concerning our common stock may be found under the caption heading "Stock Price Information" in our Annual Report to Shareholders for fiscal year 2006, which is incorporated by reference herein. Equity compensation plan information required by this item may be found in Note 3 to Consolidated Financial Statements contained in our Annual Report to Shareholders for fiscal year 2006, which is incorporated by reference herein. ITEM 6. SELECTED FINANCIAL DATA Information required by this item may be found under the caption "Five Year Financial Review" in our Annual Report to Shareholders for fiscal year 2006, which is incorporated by reference herein. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Information required by this item may be found in our Annual Report to Shareholders for fiscal year 2006, which is incorporated by reference herein. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Information required by this item may be found under the caption "Disclosures About Market Risk" in the Company's Annual Report to Shareholders for fiscal year 2006, which is incorporated by reference herein. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Information required by this item may be found in our Annual Report to Shareholders for fiscal year 2006, which is incorporated by reference herein. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. ITEM 9A. CONTROLS AND PROCEDURES (a) Evaluation of Disclosure Controls and Procedures Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures as of the end of the period covered by this report have been designed and are effective at the reasonable assurance level so that the information required to be disclosed by us in our periodic SEC filings is recorded, processed, summarized and reported within the time periods specific in the SEC's rules and forms. We believe that a controls system, no matter how well designed and operated, cannot provide absolute assurance that the objectives of the controls system are met, and no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a company have been detected. (b) Management's Annual Report on Internal Control over Financial Reporting A copy of our Management's Report of Internal Control over Financial Reporting is included in our Annual Report to Shareholders for fiscal year 2006, which is incorporated by reference herein. (c) Attestation Report of the Independent Registered Public Accounting Firm. 18 A copy of the attestation report of PricewaterhouseCoopers, LLP, our independent registered public accounting firm is included in our Annual Report to Shareholders for fiscal year 2006, which is incorporated by reference herein. (d) Change in Internal Control over Financial Reporting No change in our internal control over financial reporting occurred during the fiscal quarter covered by this report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. ITEM 9B. OTHER INFORMATION None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY This information is incorporated by reference from our definitive Proxy Statement for the Annual Meeting of Shareholders to be held February 8, 2007, to be filed with the SEC not later than 120 days after the end of the fiscal year covered by this Form 10-K. ITEM 11. EXECUTIVE COMPENSATION This information is incorporated by reference from our definitive Proxy Statement for the Annual Meeting of Shareholders to be held February 8, 2007, to be filed with the SEC not later than 120 days after the end of the fiscal year covered by this Form 10-K. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT This information is incorporated by reference from our definitive Proxy Statement for the Annual Meeting of Shareholders to be held February 8, 2007, to be filed with the SEC not later than 120 days after the end of the fiscal year covered by this Form 10-K. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS This information is incorporated by reference from our definitive Proxy Statement for the Annual Meeting of Shareholders to be held February 8, 2007, to be filed with the SEC not later than 120 days after the end of the fiscal year covered by this Form 10-K. ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES This information is incorporated by reference from our definitive Proxy Statement for the Annual Meeting of Shareholders to be held February 8, 2007, to be filed with the SEC not later than 120 days after the end of the fiscal year covered by this Form 10-K. PART IV ITEM 15. EXHIBITS AND FINANCIAL STATEMENTS (a) FINANCIAL STATEMENTS AND EXHIBITS 1. and 2. FINANCIAL STATEMENTS AND SCHEDULES The following financial statements, together with the report of PricewaterhouseCoopers LLP dated December 12, 2006 appearing in our Annual Report to Shareholders for fiscal year 2006, are incorporated by reference herein: Report of Independent Registered Public Accounting Firm Consolidated Balance Sheets as of September 30, 2006 and 2005 19 Consolidated Statements of Operations for each of the three years in the period ended September 30, 2006 Consolidated Statements of Cash Flows for each of the three years in the period ended September 30, 2006 Consolidated Statements of Changes in Shareholders' Equity for each of the three years in the period ended September 30, 2006 Notes to Consolidated Financial Statements 3. MANAGEMENT CONTRACTS AND COMPENSATORY PLANS OR ARRANGEMENTS The management contracts and compensatory plans or arrangements required to be filed as exhibits to this report are as follows: Atwood Oceanics, Inc. 1996 Incentive Equity Plan - See Exhibit 10.1.1 hereof. Form of Atwood Oceanics, Inc. Stock Option Agreement (1996 Incentive Equity Plan) - See Exhibit 10.1.2 hereof. Amendment No. 1 to Atwood Oceanics, Inc. 1996 Incentive Equity Plan - See Exhibit 10.1.3 hereof. Form of Amendment No. 1 to the Atwood Oceanics, Inc. Stock Option Agreement (1996 Incentive Equity Plan) - See Exhibit 10.1.4 hereof. Amendment No. 2 to Atwood Oceanics, Inc. 1996 Incentive Equity Plan - See Exhibit 10.1.5 hereof. Amended and Restated Atwood Oceanics, Inc. 2001 Stock Incentive Plan - See Exhibit 10.1.6 hereof. Form of Atwood Oceanics, Inc. Stock Option Agreement (2001 Stock Incentive Plan) - See Exhibit 10.1.7 hereof. Form of Atwood Oceanics, Inc. Restricted Stock Award Agreement (2001 Stock Incentive Plan) - See Exhibit 10.1.8 hereof. Form of Non-Employee Director Restricted Stock Award Agreement Amended and Restated 2001 Stock Incentive Plan - See Exhibit 10.1.9 hereof. Atwood Oceanics, Inc. Retention Plan for Certain Salaried Employees dated effective as of January 1, 2006 - See Exhibit 10.2.1 hereof. Atwood Oceanics, Inc. Retention Plan for Certain Salaried Employees dated effective as of January 1, 2007 - See Exhibit 10.2.2 hereof. Executive Agreement dated as of September 18, 2002 between the Company and John R. Irwin - See Exhibit 10.3.1 hereof. Executive Agreement dated as of September 18, 2002 between the Company and James M. Holland - See Exhibit 10.3.2 hereof. Executive Agreement dated as of September 18, 2002 between the Company and Glen P. Kelley - See Exhibit 10.3.3 hereof. (b) See the "EXHIBIT INDEX" for a listing of all of the Exhibits filed as part of this report. (c) NONE 20 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. ATWOOD OCEANICS, INC. /S/JOHN R. IRWIN ----------------------- JOHN R. IRWIN, President and Chief Executive Officer DATE: December 13, 2006 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. /S/ JAMES M. HOLLAND /S/ JOHN R. IRWIN - -------------------- ----------------- JAMES M. HOLLAND JOHN R. IRWIN Senior Vice President President, Chief Executive and Chief Financial Officer Officer and Director (Principal Financial and Accounting Officer) (Principal Executive Officer) Date: December 13, 2006 Date: December 13, 2006 /S/ ROBERT W. BURGESS /S/ GEORGE S. DOTSON - --------------------- -------------------- ROBERT W. BURGESS GEORGE S. DOTSON Director Director Date: December 13, 2006 Date: December 13, 2006 /S/ HANS HELMERICH /S/ WILLIAM J. MORRISSEY - ------------------ ------------------------ HANS HELMERICH WILLIAM J. MORRISSEY Director Director Date: December 13, 2006 Date: December 13, 2006 /S/ DEBORAH A. BECK /S/JAMES R. MONTAGUE - ------------------- --------------------- DEBORAH A. BECK JAMES R. MONTAGUE Director Director DATE: December 13, 2006 DATE: December 13, 2006 21 EXHIBIT INDEX 3.1 Amended and Restated Certificate of Formation dated February 9, 2006 (Incorporated herein by reference to Exhibit 3.1 of our Form 8-K filed February 14, 2006). 3.2 Second Amended and Restated By-Laws dated May 5, 2006 (Incorporated herein by reference to Exhibit 3.2 of our Form 10-Q filed May 10, 2006). 4.1 Rights Agreement dated effective October 18, 2002 between the Company and Continental Stock Transfer & Trust Company (Incorporated herein by reference to Exhibit 4.1 of our Form 8-A filed October 21, 2002). 4.2 Certificate of Adjustment of Atwood Oceanics, Inc. dated March 17, 2006 (Incorporated herein by reference to Exhibit 4.1 of our Form 8-K filed March 23, 2006). 10.1.1 Atwood Oceanics, Inc. 1996 Incentive Equity Plan (Incorporated herein by reference to Exhibit 10.1 of our Form 10-Q for the quarter ended June 30, 1997). 10.1.2 Form of Atwood Oceanics, Inc. Stock Option Agreement - 1996 Incentive Equity Plan (Incorporated herein by reference to our Form 10-K for the year ended September 30, 1999). 10.1.3 Amendment No. 1 to the Atwood Oceanics, Inc. 1996 Incentive Equity Plan (Incorporated herein by reference to our Form 10-K for the year ended September 30, 1999). 10.1.4 Form of Amendment No. 1 to the Atwood Oceanics, Inc. Stock Option Agreement - 1996 Incentive Equity Plan (Incorporated herein by reference to Exhibit 10.3.4 of our Form 10-K for the year ended September 30, 1999). 10.1.5 Amendment No. 2 to the Atwood Oceanics, Inc. 1996 Incentive Equity Plan (Incorporated herein by reference to Appendix A to our Form DEF 14A filed January 12, 2001). 10.1.6 Atwood Oceanics, Inc. Amended and Restated 2001 Stock Incentive Plan (Incorporated herein by reference to Appendix D to our definitive proxy statement on Form DEF 14A filed January 13, 2006). 10.1.7 Form of Atwood Oceanics, Inc. Stock Option Agreement - 2001 Stock Incentive Plan (Incorporated herein by reference to Exhibit 10.3.7 of our Form 10-K for the year ended September 30, 2005). 10.1.8 Form of Atwood Oceanics, Inc. Restricted Stock Award Agreement - 2001 Stock Incentive Plan. (Incorporated herein by reference to Exhibit 10.3.8 of our Form 10-K for the year ended September 30, 2005). 10.1.9 Form of Non-Employee Director Restricted Stock Award Agreement Amended and Restated 2001 Stock Incentive Plan (Incorporated herein by reference to Exhibit 10.1 of our Form 8-K filed June 1, 2006). 10.2.1 Atwood Oceanics, Inc. Retention Plan for Certain Salaried Employees effective as of January 1, 2006 (Incorporated herein by reference to Exhibit 10.4.2 of our Form 10-K for the year ended September 30, 2005). *10.2.2 Atwood Oceanics, Inc. Retention Plan for Certain Salaried Employees dated as of January 1, 2007. 10.3.1 Executive Agreement dated as of September 18, 2002 between the Company and John R. Irwin (Incorporated herein by reference to Exhibit 10.5.1 of our Form 10-K for the year ended September 30, 2002). 10.3.2 Executive Agreement dated as of September 18, 2002 between the Company and James M. Holland (Incorporated herein by reference to Exhibit 10.5.2 of our Form 10-K for the year ended September 30, 2002). 10.3.3 Executive Agreement dated as of September 18, 2002 between the Company and Glen P. Kelley (Incorporated herein by reference to Exhibit 10.5.3 of our Form 10-K for the year ended September 30, 2002). 10.4 Credit Agreement for $225 million dated April 1, 2003 among the Company, Atwood Oceanics Pacific Limited and Nordea Bank Finland Plc and other Financial Institutions (Incorporated herein by reference to Exhibit 99.1 of our 8-K filed April 7, 2003). 22 10.5 Pooled Assignment and First Amendment to Credit Agreement dated June 27, 2003 among the Company, Atwood Oceanics Pacific Limited and Nordea Bank Finland Plc and other Financial Institutions (Incorporated herein by reference to Exhibit 99.1 of our Form 8-K filed July 30, 2003). 10.6 Second Amendment to Credit Agreement dated June 27, 2003 among the Company, Atwood Oceanics Pacific Limited and Nordea Bank Finland Plc and other Financial Institutions (Incorporated herein by reference to Exhibit 99.2 of our Form 8-K filed July 30, 2003). 10.7 Third Amendment to Credit Agreement dated November 12, 2003 among the Company, Atwood Oceanics Pacific Limited and Nordea Bank Finland Plc and other Financial Institutions (Incorporated herein of reference to Exhibit 99.2 of our Form 8-K filed November 13, 2003). 10.8 Platform Construction Agreement by and between Atwood Oceanics Pacific Limited and Keppel AmFELS , Inc. dated March 1, 2006 (Incorporated herein by reference to Exhibit 10.1 of our Form 8-K filed March 2, 2006). *13.1 Annual Report to Shareholders. *21.1 List of Subsidiaries. *23.1 Consent of Independent Registered Public Accounting Firm. *31.1 Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. *31.2 Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. *32.1 Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. *32.2 Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. *Filed herewith 23 EX-10 2 exhibit1022.txt EXHIBIT 10.2.2 ----------------------------------- ATWOOD OCEANICS, INC. RETENTION PLAN FOR CERTAIN SALARIED EMPLOYEES ----------------------------------- Effective as of January 1, 2007 This Plan will terminate automatically as of December 31, 2007 if there is no "Effective Date" (as defined in Plan Section 1.5) on or before that date. ATWOOD OCEANICS, INC. RETENTION PLAN FOR CERTAIN SALARIED EMPLOYEES The Company (as defined herein) hereby adopts this Retention Plan for Certain Salaried Employees (the "Plan"), effective as of the 1st day of January, 2007. INTRODUCTION The purpose of this Plan is to secure the interests of the Company's shareholders in the event of a change of control of the Company. In such an event, this Plan would provide an enhanced severance payment and other benefits to encourage certain valued employees to remain employed with the Company during that period of financial uncertainty preceding and following the change of control. If such an event does not occur on or before December 31, 2007, this Plan will terminate automatically, unless otherwise renewed by the Company's Board of Directors. ARTICLE I DEFINITIONS Terms defined above and initially capitalized shall have the respective meanings so ascribed. When used in this Plan and initially capitalized, the following words and phrases shall have the following respective meanings unless the context clearly requires otherwise: 1.1 "Base Salary" as to any Covered Employee for any period, shall mean the greater of the sum of such individual's monthly base salary and Bonus as of the Termination of Employment or as of the date immediately preceding the Effective Date, which is paid to such individual by the Company during employment for such period, before reduction because of an election between benefits or cash provided under a plan of the Company maintained pursuant to Section 125 or 401(k) of the Internal Revenue Code of 1986, as amended, and before reduction for any other amounts contributed by the Company on such individual's behalf to any other employee-benefit plan. 1.2 "Bonus" as to Covered Employee for any period, shall mean the average of bonus payments, if any, made over the preceding three years, including any year for which a bonus has been awarded but not paid, divided by twelve. If the Covered Employee has not been an employee of the Company for at least three years, then Bonus shall be calculated over the period for which the employee has been employed with the Company. 1.3 "Company" shall mean Atwood Oceanics, Inc., a Texas corporation, or any entity that is a successor to it in ownership of substantially all its assets and their affiliates ("Atwood") and its direct and indirect subsidiaries. 1.4 "Covered Employee" shall mean an employee described in Article II of the Plan. 1.5 "Effective Date" shall mean the date on or before December 31, 2007, on which any of the following is effective: (a) The acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended (the "Exchange Act")) (a "Person") of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of twenty percent (20%) or more of either (i) the then outstanding shares of common stock of Atwood or (ii) the combined voting power of the then outstanding voting securities of Atwood entitled to vote generally in the election of directors; provided, however, that the following acquisitions shall not constitute a Change of Control: (i) any acquisition directly from Atwood; (ii) any acquisition 2 by Atwood; (iii) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company; or (b) Atwood shall sell substantially all of its assets to another corporation which is not a wholly owned subsidiary; or (c) Individuals who, as of the date hereof, constitute the Board of Atwood (the "Incumbent Board") cease for any reason to constitute at least a majority of the Board; provided, however, that any individual becoming a director subsequent to the date hereof whose election, or nomination for election by Atwood's shareholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board. 1.6 "Employment Year" shall mean a period which commences on the first date of employment or any anniversary of such date and ends one year from such date. 1.7 "Good Cause" shall mean a material violation of a Company policy or procedure applicable to employees in the same or similar job position, the willful disregard or failure to follow the reasonable instructions of a superior, the taking of any action, or the failure to take any action, which results in a damage or detriment to the Company, or the conviction of an employee of a felony involving moral turpitude. 1.8 "Health and Life Benefits" shall mean as to any employee, the group-health and life-insurance benefits sponsored by the Company for its full-time employees and provided to or elected by such individual as of the date immediately preceding the Effective Date. 1.9 "Other Severance" shall have the meaning set forth in Section 2.2 of the Plan. 1.10 "Severance Pay" shall mean the sum payable to a Covered Employee upon Termination of Employment as set forth in Section 3.1 of the Plan. 1.11 "Term" shall mean the period commencing on the Effective Date and ending one year after that date. 1.12 "Termination of Employment" shall mean a termination of employment with the Company at the option of the Company for any reason, except a termination of employment for Good Cause shall not mean a Termination of Employment. 1.13 "Years of Continuous Service" shall mean, as to any employee, all full or partial years during which he was employed on a full-time basis by the Company. ARTICLE II. COVERED EMPLOYEES 2.1 Who is a Covered Employee. Any employee of the Company who upon the occurrence of an Effective Date, shall be listed in Schedule 3.1 hereto, which Schedule 3.1 shall be amended from time to time by the Company, and who has a Termination of Employment during the Term shall be a Covered Employee and eligible to receive the benefits described in this Plan. 2.2 Exclusions. Any employee who otherwise is a Covered Employee but who, pursuant to a separate agreement signed on behalf of the Company, receives severance or other salary continuation benefits upon a Termination of Employment (other than payments or benefits under the Company's Executive Life Insurance Plan) shall not be a Covered Employee under this Plan. This Plan shall be in lieu of any plan, program, policy or practice of or contract or agreement with the Company relating to severance of employment ("Other Severance") and any and 3 all benefits of payments arising out of or relating to Other Severance shall be fully offset against any benefits or payments due and owing hereunder. ARTICLE III SEVERANCE PAY AND OTHER BENEFITS 3.1 Amount of Severance Pay. The Company shall pay Severance Pay to a Covered Employee upon a Termination of Employment in an amount equal to the greater of (a) or (b): (a) such individual's weekly Base Salary multiplied by such individual's Years of Continuous Service; or (b) a payment, depending upon the category of employee as identified in Schedule 3.1 hereto, as follows: Category of Employee Payment -------------------- ------- Houston Management A: (i) Less than 4 Years of Continuous Service - 6 months' Base Salary; or (ii) 4 Years but less than 8 Years of Continuous Service - 12 months' Base Salary; or (iii) 8 or greater Years of Continuous Service - 18 months' Base Salary Houston Management B, Houston Technical, Rig Management and Other Administration: (i) Less than 4 Years of Continuous Service - 1 month Base Salary; or (ii) 4 Years but less than 8 Years of Continuous Service - 4 months' Base Salary; or (iii) 8 Years but less than 12 Years of Continuous Service - 8 months' Base Salary; or (iv) 12 or greater Years of Continuous Service - 12 months' Base Salary Houston Accounting A, Houston Accounting B and Houston Staff: (i) Less than 4 Years of Continuous Service - 1 month Base Salary; or (ii) 4 Years but less than 8 Years of Continuous Service - 3 months' Base Salary; or (iii) 8 or greater Years of Continuous Service - 6 months' Base Salary 4 3.2 Health and Life Benefits. Upon a Termination of Employment, a Covered Individual's Health and Life Benefits shall be treated as follows: (a) Upon a Termination of Employment and if applicable, the Company will notify each Covered Employee of the right to elect to continue any Company-provided health or disability benefits, all in accordance with and subject to the provisions of the Consolidated Omnibus Budget Reconciliation Act ("COBRA"). The Company shall charge the maximum allowable premium in connection with any COBRA benefits so provided. Other than the benefits provided under COBRA, the Company shall have no further obligation to provide health or disability insurance benefits to any Covered Individual following a Termination of Employment. (b) Upon written request by a Covered Individual within five (5) days of a Termination of Employment, the Company shall assign any life, salary continuation or travel insurance plans or policies to such Covered Individual which by their terms are so assignable, and such Covered Individual will thenceforth become responsible for the payment of any premiums required to maintain said plans or policies from and after the date of Termination of Employment; otherwise, the Company will cease to continue such life insurance plans or policies on behalf of any Covered Employee effective as of the date of Termination of Employment. 3.3 Payment for Unused Vacation. Upon a Termination of Employment, the Company will pay a Covered Employee an amount equal to such individual's weekly Base Salary multiplied by each full and partial week of vacation, which was accrued but unused during the Employment Year in which occurred such individual's Termination of Employment. For purposes of determining payment under this Section 3.3, a full week of vacation consists of five (5) vacation days. ARTICLE IV DISTRIBUTION OF CASH PAYMENTS The Company shall pay a Covered Employee the amount to which he or she is entitled under (as applicable) Plan Section 3.1 (relating to Severance Pay) and Plan Section 3.3 (relating to Payment for Unused Vacation) in one lump sum within a reasonable time, but in no event greater than ten (10) business days, after such Covered Employee's Termination of Employment. ARTICLE V ADMINISTRATION OF PLAN 5.1 In General. The Plan shall be administered by Atwood, which shall be the named fiduciary under the Plan. Atwood may delegate any of its administrative duties, including without limitation duties with respect to the processing, review, investigation, approval, and payment of benefits under the Plan, to a named administrator or administrators. 5.2 Regulations. Atwood shall promulgate any rules and regulations that it deems necessary to carry out the purposes of the Plan, or to interpret the terms and conditions of the Plan; provided that no rule, regulation, or interpretation shall be contrary to the provisions of the Plan. The rules, regulations, and interpretations made by Atwood shall, subject only to the claims procedure outlined in Section 5.3 hereof, be final and binding on any employee or former employee of the Company, or any successor in interest of either. 5.3 Claims Procedure. The Company shall determine the rights of any employee or former employee of the Company to any benefits hereunder. Any employee or former employee of the Company who believes that he is entitled to receive any benefits other than as initially determined by the Company, may file a claim in writing with Atwood's President. Atwood shall, no later than ninety (90) days after the receipt of a claim, either allow or deny the claim in writing. 5 A denial of a claim, wholly or partially, shall be written in a manner calculated to be understood by the claimant and shall include: (a) the specific reason or reasons for the denial; (b) specific reference to pertinent Plan provisions on which the denial is based; (c) a description of any additional material or information necessary for the claimant to perfect the claim and an explanation of why such material or information is necessary; and (d) an explanation of the claim-review procedure. A claimant whose claim is denied (or his duly authorized representative) may, within 30 days after receipt of denial of his claim: (a) request a review upon written application to the Company's personnel administrator; (b) review pertinent documents; and (c) submit issues and comments in writing. Atwood shall notify the claimant of its decision on review within sixty (60) days after receipt of a request for review. Notice of the decision on review shall be in writing. 5.4 Revocability of Company Action. Any action taken by Atwood with respect to the rights under the Plan of any employee or former employee shall be revocable by Atwood as to payments or distributions not yet made to such person, and acceptance of any benefits under the Plan constitutes acceptance of and agreement to any appropriate adjustments made by the Company in future payments or distributions to such person to offset any excess or underpayment previously made to him with respect to any benefits. ARTICLE VI AMENDMENT OR TERMINATION OF PLAN 6.1 Right to Amend or Terminate. Atwood reserves the right at any time prior to the Effective Date, and without prior or other approval of any employee or former employee, to change, modify, amend, or terminate the Plan. All such changes, modifications, or amendments may be retroactive to any date up to and including the original effective date of the Plan, and shall be retroactive to that date unless other provision is specifically made; provided that no such change, modification, or amendment shall adversely affect any benefit under the Plan previously paid or provided to a Covered Employee (or his or her successor in interest). 6.2 Automatic Termination. This Plan shall terminate automatically as of December 31, 2007, or such other extended termination date duly adopted in accordance with the provisions of Section 6.1 above, if there is no Effective Date on or before that date. Termination pursuant to this Plan Section 6.2 shall occur without any action on the part of the Company and shall be effective without prior notice to or approval of any employee or former employee of the Company. ARTICLE VII METHOD OF FUNDING The Company shall pay benefits under the Plan from current operating funds. No property of the Company is or shall be, by reason of this Plan, held in trust for any employee of the Company, nor shall any person have any interest in or any lien or prior claim upon any property of the Company by reason of the Plan or the Company's obligations to make payments hereunder. ARTICLE VIII LEGAL FEES AND EXPENSES; ENFORCEMENT It is the intent of the Company that no Covered Employee be required to incur the expenses associated with the enforcement of his rights under this Plan by litigation or other legal action because the cost and expense thereof would substantially detract from the benefits intended to be extended to a Covered 6 Employee hereunder. Accordingly, if it should appear to a Covered Employee that the Company has failed to comply with any of its obligations under this Plan or in the event that the Company or any other person takes any action inconsistent with the terms of this Plan to declare this Plan void or unenforceable, or institutes any litigation designed to deny, or to recover from, the Covered Employee the benefits intended to be provided to such Covered Employee hereunder, the Company irrevocably authorizes such Covered Employee from time to time to retain counsel of his choice, at the expense of the Company as thereafter provided, to represent such Covered Employee in connection with the initiation or defense of any litigation or other legal action, whether by or against the Company or any director, officer, stockholder, or other person affiliated with the Company in any jurisdiction. Notwithstanding any existing prior attorney-client relationship between the Company and such counsel, the Company irrevocably consents to such Covered Employee's entering into an attorney-client relationship with such counsel, and in that connection the Company and such Covered Employee agree that a confidential relationship shall exist between such Covered Employee and such counsel. The Company shall pay and be solely responsible for any and all attorneys' and related fees and expenses incurred by such Covered Employee as a result of the Company's failure to perform under this Plan or any provision thereof; or as a result of the Company or any person contesting the validity or enforceability of this Plan or any provision thereof. ARTICLE IX MISCELLANEOUS 9.1 Limitation on Rights. Participation in the Plan shall not give any employee the right to be retained in the service of the Company or any rights to any benefits whatsoever, except to the extent specifically set forth herein. Unless otherwise agreed in writing, employment with the Company is "at will." 9.2 Headings. Headings of Articles and Sections in this instrument are for convenience only, and do not constitute any part of the Plan. 9.3 Gender and Number. Unless the context clearly indicates otherwise, the masculine gender when used in the Plan shall include the feminine, and the singular number shall include the plural and the plural number the singular. 7 EXECUTED as of the date first set forth above. ATWOOD OCEANICS, INC. By: /s/ John R. Irwin Name: John R. Irwin Title: President & Chief Executive Officer 8 EX-13 3 exh131.txt EXHIBIT 13.1 2006 ANNUAL REPORT TO SHAREHOLDERS THE COMPANY This Annual Report is for Atwood Oceanics, Inc. and its subsidiaries, which are collectively referred to as "we", "our", or the "Company" except where stated otherwise. We are engaged in the international offshore drilling and completion of exploratory and developmental oil and gas wells and related support, management and consulting services. Presently, we own and operate a premium, modern fleet of eight mobile offshore drilling units and manage the operations of two operator-owned platform drilling units currently located in Northwest Australia. Since fiscal year 1997, we invested approximately $510 million in upgrading seven mobile offshore drilling units and constructing an ultra-premium jack-up unit, the ATWOOD BEACON. Upon its expected delivery on or before September 2008, the ATWOOD AURORA will be our ninth active mobile offshore drilling unit. We support our operations from our Houston headquarters and offices currently located in Australia, Malaysia, Malta, Egypt, Indonesia, Singapore and the United Kingdom. FINANCIAL HIGHLIGHTS 2006 2005 ---- ---- (In Thousands) FOR THE YEAR ENDED SEPTEMBER 30: REVENUES $276,625 $176,156 NET INCOME 86,122 26,011 CAPITAL EXPENDITURES 78,464 25,563 AT SEPTEMBER 30: NET PROPERTY AND EQUIPMENT $436,166 $390,778 TOTAL ASSETS 593,829 495,694 TOTAL SHAREHOLDERS' EQUITY 458,894 362,137 1 TO OUR SHAREHOLDERS AND EMPLOYEES: We are pleased to report revenues, operating cash flows and net income for fiscal year 2006 were the highest in our thirty-nine year history. Our net income of $86 million, or $2.74 per diluted share, was more than twice our previous record net income in fiscal year 1998. Fiscal year 2006 ends with the Company in a strong position for the future. Our fleet utilization for the fiscal year was 100% and there were a number of accomplishments during the fiscal year in other key areas. Our contract backlog in terms of available rig days for our eight units, all contracted at historically high dayrates, is approximately 95% for fiscal year 2007, 80% for fiscal year 2008 and 40% for fiscal year 2009. This contract backlog provides strong upside visibility for fiscal year 2007 and further upside potential beyond fiscal year 2007, particularly with our deepwater and international jack-up leverage and with the ATWOOD HUNTER, ATWOOD SOUTHERN CROSS and RICHMOND contracts repricing in fiscal year 2008. Also, this year, our future visibility is enhanced with the change from well or well-to-well contracts to term contracts on the VICKSBURG, ATWOOD HUNTER, ATWOOD FALCON, SEAHAWK and ATWOOD BEACON. The ATWOOD SOUTHERN CROSS has a contract that continues into fiscal year 2008, and the ATWOOD EAGLE has a two-year contract at a high dayrate, currently estimated to commence in the first quarter of fiscal year 2009. Our new, ultra-premium jack-up, the ATWOOD AURORA, scheduled for delivery on or before September 2008, will offer growth potential when it commences operation as our ninth owned offshore drilling unit. Our remaining unit, the RICHMOND, is operating in the U.S. Gulf of Mexico. The RICHMOND has operated profitably in the Gulf of Mexico for many years. We continue to focus daily on safe, high standards of performance, our people and the continuing development of our organization for the future. Our safety and operational performance this fiscal year has been recognized by many of our clients. The Company also continued its fleet upgrade, enhancement and new construction program during the year with the successful completion of three shipyard update projects (the ATWOOD SOUTHERN CROSS, SEAHAWK and ATWOOD FALCON). Total expenditures of approximately $50 million for these projects brought our total project expenditures, since 1997, for fleet upgrade, renewal and construction completed, to over $500 million. Construction of our new, ultra-premium jack-up, the ATWOOD AURORA, also commenced this year. We are pleased with the Company's current position: a strong balance sheet with a current debt to total capitalization ratio of approximately 12% and a continuing trend for improvements in cash flows and financial results at historic levels. The demand by our clients for the services and equipment that our Company provides continues at a high level. Our strategy of focusing on safe, quality operations, premium equipment, long-standing client relationships, and being leveraged to attractive international markets has served us well - and we believe will serve us well in the future. We are in a position to be opportunistic, when the time is right, and, accordingly, continue to pursue and explore other future opportunities, as well as evaluating the best use of future cash flow balances. As always, we thank our shareholders for their confidence and our employees for their many contributions and achievements during fiscal year 2006, and we look forward to fiscal year 2007. /S/ JOHN R. IRWIN John R. Irwin 2 Atwood Oceanics, Inc. and Subsidiaries FIVE YEAR FINANCIAL REVIEW (In thousands, except per share amounts, fleet At or For the Years Ended September 30, data and ratios) 2006 2005 2004 2003 2002 - -------------------------------------------------------------------------------------------------------------------------------- STATEMENTS OF OPERATIONS DATA: Revenues $ 276,625 $ 176,156 $163,454 $144,765 $149,157 Contract drilling costs (144,366) (102,849) (98,936) (98,500) (75,088) Depreciation (26,401) (26,735) (31,582) (25,758) (23,882) General and administrative expenses (20,630) (14,245) (11,389) (14,015) (10,080) Gain on sale of equipment 10,548 - - - - -------- -------- -------- -------- -------- OPERATING INCOME 95,776 32,327 21,547 6,492 40,107 Other expense (3,940) (6,719) (9,145) (4,856) (1,330) Tax (provision) benefit (5,714) 403 (4,815) (14,438) (10,492) -------- -------- -------- -------- ------- NET INCOME (LOSS) $ 86,122 $ 26,011 $ 7,587 $(12,802) $ 28,285 ========= ======== ======== ======== ======== PER SHARE DATA(1): Earnings (loss) per common share: Basic $ 2.78 $ 0.86 $ 0.27 $ (0.46) $ 1.02 Diluted $ 2.74 $ 0.83 $ 0.27 $ (0.46) $ 1.01 Average common shares outstanding: Basic 30,936 30,412 27,718 27,692 27,678 Diluted 31,442 31,220 28,064 27,692 27,988 FLEET DATA: Number of rigs owned or managed, at end of period 10 11 11 11 10 Utilization rate for in-service rigs (2) 100% 98% 93% 92% 86% BALANCE SHEET DATA: Cash and cash equivalents $ 32,276 $ 18,982 $ 16,416 $ 21,551 $ 27,655 Working capital 86,308 35,894 32,913 26,063 43,735 Net property and equipment 436,166 390,778 401,141 443,102 368,397 Total assets 593,829 495,694 498,936 522,674 445,238 Total long-term debt (including current portion) 64,000 90,000 181,000 205,000 115,000 Shareholders' equity (3) (4) 458,894 362,137 271,589 263,467 276,133 Ratio of current assets to current liabilities 2.41 1.64 1.55 1.52 2.44
Notes - (1) Fiscal years 2005, 2004, 2003 and 2002 have been restated to reflect a two-for-one stock split effected on March 2, 2006. See Note 7 to the consolidated financial statements for further dicussion. (2) Excludes managed rigs, the SEASCOUT (sold in fiscal year 2006), and contractual downtime on rigs upgraded. (3) We have never paid any cash dividends on our common stock. (4) In October 2004, we sold 2,350,000 shares of common stock in a public offering. 3 OFFSHORE DRILLING OPERATIONS - ----------------------------------------------------------------------------------------------------------------------------------- MAXIMUM PERCENTAGE LOCATION AT YEAR WATER OF FY 2006 DECEMBER 12, CONTRACT STATUS AT RIG NAME UPGRADED DEPTH REVENUES 2006 CUSTOMER DECEMBER 12, 2006 -------- --------- ----- -------- ------------ -------- ----------------- SEMISUBMERSIBLES - ATWOOD EAGLE 2000/2002 5,000 Ft. 17% Offshore BHP BILLITON The rig is currently working under a Australia PETROLEUM PTY drilling program for BHPB which could ("BHPB") extend, if all option wells are drilled, to November 2007. Upon completion of this drilling commitment, the rig has a one (1) well contract commitment with ENI Australia BV, followed by a two (2) year contract commitment with Woodside Energy, Ltd. It should take until December 2009 before these drilling commitments are completed. ATWOOD HUNTER 1997/2001 5,000 Ft. 23% Offshore WOODSIDE ENERGY, The rig is currently working under a Mauritania LTD. ("WOODSIDE") drilling program for Woodside which extends to April 2008. ATWOOD FALCON 1998/2006 5,000 Ft. 11% Offshore SARAWAK SHELL The rig is currently working under a Malaysia BERHAD ("SHELL") long-term drilling commitment with Shell which extends to July 2009. 4 ATWOOD SOUTHERN 1997/2006 2,000 Ft. 11% Offshore TOREADOR TURKEY The rig is currently working under CROSS Turkey LIMITED drilling commitments for six (6) wells ("TOREADOR") plus two (2) options for Toreador and AND MELROSE Melrose which could take until July 2007 RESOURCES to complete. Following completion of ("MELROSE") these commitments, the rig has drilling commitments in the Black Sea for Turkiye Petrolleri A.O. and Vanco which could extend to April 2008. CANTILEVER JACK-UPS - ATWOOD BEACON Constructed 400 Ft. 12% Offshore GUJARAT STATE The rig is currently being mobilized to in 2003 India PETROLEUM India to commence a twenty-five (25) CORPORATION LTD. month contract for GSPC. ("GSPC") VICKSBURG 1998 300 Ft. 11% Offshore CHEVRON OVERSEAS The rig is currently working under a Thailand PETROLEUM long-term drilling commitment for Chevron ("CHEVRON") which will extend to June 2009. ATWOOD AURORA Under 400 Ft. 0% N/A N/A The rig is under construction in Construction Brownsville, Texas with expected completion on or before September 2008. 5 SUBMERSIBLE - RICHMOND 2000/2002 70 Ft. 7% U.S. Gulf of HELIS OIL & The rig is currently working for Helis Mexico GAS ("HELIS") under a contract which could extend to May/June 2007. SEMISUBMERSIBLE TENDER ASSIST UNIT - SEAHAWK 1992/1999/ 600 Ft. 4% Offshore AMERADA HESS The rig is currently working under a 2006 Equatorial EQUATORIAL two-year contractual commitment with Hess Guinea GUINEA, INC. which extends to September 2008. Hess ("HESS") also has four (4) six-month options. MODULAR PLATFORMS - MANAGEMENT CONTRACT GOODWYN `A' and N/A 4%* Australia WOODSIDE Both the GOODWYN `A' and NORTH RANKIN `A' NORTH RANKIN `A' are idle with planned breaks in drilling We are currently providing rig maintenance services to these rigs. *For both units, collectively.
6 SECURITIES LITIGATION SAFE HARBOR STATEMENT Statements included in this report which are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions related thereto) are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. In addition, we and our representatives may from to time to time make other oral or written statements which are also forward-looking statements. These forward-looking statements are made based upon management's current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements. Important factors that could cause our actual results of operations or our actual financial conditions to differ include, but are not necessarily limited to: * our dependence on the oil and gas industry; * the operational risks involved in drilling for oil and gas; * changes in rig utilization and dayrates in response to the level of activity in the oil and gas industry, which is significantly affected by indications and expectations regarding the level and volatility of oil and gas prices, which in turn are affected by such things as political, economic and weather conditions affecting or potentially affecting regional or worldwide demand for oil and gas, actions or anticipated actions by OPEC, inventory levels, deliverability constraints, and future market activity; * the extent to which customers and potential customers continue to pursue deepwater drilling; * exploration success or lack of exploration success by our customers and potential customers; * the highly competitive and cyclical nature of our business, with periods of low demand and excess rig availability; * the impact of the war with Iraq or other military operations, terrorist acts or embargoes elsewhere; * our ability to enter into and the terms of future drilling contracts; * the availability of qualified personnel; * our failure to retain the business of one or more significant customers; * the termination or renegotiation of contracts by customers; * the availability of adequate insurance at a reasonable cost; * the occurrence of an uninsured loss; * the risks of international operations, including possible economic, political, social or monetary instability, and compliance with foreign laws; * the effect public health concerns could have on our international operations and financial results; * compliance with or breach of environmental laws; * the incurrence of secured debt or additional unsecured indebtedness or other obligations by us or our subsidiaries; 7 * the adequacy of sources of liquidity; * currently unknown rig repair needs and/or additional opportunities to accelerate planned maintenance expenditures due to presently unanticipated rig downtime; * higher than anticipated accruals for performance-based compensation due to better than anticipated performance by us, higher than anticipated severance expenses due to unanticipated employee terminations, higher than anticipated legal and accounting fees due to unanticipated financing or other corporate transactions, and other factors that could increase general and administrative expenses; * the actions of our competitors in the offshore drilling industry, which could significantly influence rig dayrates and utilization; * changes in the geographic areas in which our customers plan to operate, which in turn could change our expected effective tax rate; * changes in oil and gas drilling technology or in our competitors' drilling rig fleets that could make our drilling rigs less competitive or require major capital investments to keep them competitive; * rig availability; * the effects and uncertainties of legal and administrative proceedings and other contingencies; * the impact of governmental laws and regulations and the uncertainties involved in their administration, particularly in some foreign jurisdictions; * changes in accepted interpretations of accounting guidelines and other accounting pronouncements and tax laws; * the risks involved in the construction, upgrade, and repair of our drilling units; and * such other factors as may be discussed in our reports filed with the Securities and Exchange Commission, or SEC. These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors could also have material adverse effects on future results. The words "believe," "impact," "intend," "estimate," "anticipate," "plan" and similar expressions identify forward-looking statements. These forward-looking statements are found at various places throughout this report. When considering any forward-looking statement, you should also keep in mind the risk factors described in our Form 10-K for the year ended September 30, 2006, particularly in Item 1A Risk Factors, to which this Annual Report is an exhibit, and in other reports or filings we make with the SEC from time to time. Undue reliance should not be placed on these forward-looking statements, which are applicable only on the date hereof. Neither we nor our representatives have a general obligation to revise or update these forward-looking statements to reflect events or circumstances that arise after the date hereof or to reflect the occurrence of unanticipated events. 8 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OUTLOOK Revenues, operating cash flows and net income for fiscal year 2006 were the highest in our thirty-nine year history. All of our eight drilling units have contractual dayrate commitments that are the highest in their respective histories. Currently, we have approximately 95% and 80% of our available rig days contracted for fiscal years 2007 and 2008, respectively. A comparison of the average per day revenues for fiscal years 2006 and 2005 for each of our eight drilling units to their highest currently contracted dayrate commitment is as follows: AVERAGE AVERAGE HIGHEST PER DAY PER DAY CURRENTLY PERCENTAGE REVENUES REVENUES CONTRACTED CHANGE FOR FISCAL FOR FISCAL DAYRATE FROM FISCAL YEAR 2005 YEAR 2006 COMMITMENT YEAR 2006 ----------- ---------- ---------- ----------- ATWOOD EAGLE $95,000 $129,000 $405,000 214% ATWOOD HUNTER $61,000 172,000 245,000 42% ATWOOD FALCON $82,000 83,000 200,000 141% ATWOOD SOUTHERN CROSS $30,000 82,000 305,000 272% ATWOOD BEACON $66,000 88,000 133,500 52% VICKSBURG $65,000 82,000 154,000 88% SEAHAWK $38,000 32,000 68,430 114% RICHMOND $33,000 55,000 80,000 45%
The ATWOOD EAGLE is currently working under a contractual commitment offshore Australia at dayrates ranging from $150,000 to approximately $170,000 which should extend to November 2007. Following completion of this contract commitment, the rig will drill one (1) well at a dayrate of $360,000 and then commence a two-year contract commitment at a dayrate of $405,000 which should extend to December 2009. The ATWOOD HUNTER is currently working offshore Africa at dayrates ranging from $240,000 to $245,000 under a long-term contract commitment which should extend to April 2008. The ATWOOD FALCON has a contractual commitment offshore Malaysia at dayrates ranging from $93,000 to $200,000 which should extend into July 2009. Under this contractual commitment, during the period August 2006 to early November 2006 the rig incurred a $30 million water depth upgrade along with certain equipment refurbishments of which the customer will pay $24 million of such costs along with payment of a $90,000 dayrate during this shipyard period. The $24 million will be amortized into income on a straight-line basis over the term of the contract through July 2009. The ATWOOD SOUTHERN CROSS is currently working in the Black Sea and has several drilling commitments at dayrates ranging from $125,000 to $305,000 that should extend through the first half of fiscal year 2008. Currently, the ATWOOD BEACON is being relocated to India to commence a 25-month contract at dayrates ranging from $113,000 to $133,500. The VICKSBURG has contract commitments offshore Thailand at dayrates ranging from $94,500 to $154,000 that should extend to June 2009. The SEAHAWK is currently working offshore West Africa under a long-term drilling program that should extend to September 2008. This drilling contract provides for four six month options with a dayrate for the firm and option periods of $68,430. After the first year, the stated dayrate of $68,430 will increase based upon certain cost escalations. Our only rig in the U.S. Gulf of Mexico, the RICHMOND, has a current contract commitment at a dayrate of $80,000 which could extend to May/June 2007. The ATWOOD AURORA, an ultra premium jack-up to become our ninth owned offshore drilling unit upon its delivery, is under construction at Brownsville, Texas. The construction of this rig is currently expected to be completed on or before September 2008 at a total cost (including capitalized interest) of $160 million. 9 The current strong market environment is not only supporting high equipment utilization with historical high dayrate environments, but also has resulted in a significant increase in our operating costs. Over the next few months, we expect daily operating costs for the ATWOOD EAGLE to average between $80,000 and $85,000. The ATWOOD HUNTER, during the time it works offshore Mauritania and Libya, is expected to incur daily operating costs between $55,000 and $60,000; however, costs could be higher during any relocation period or during any period when the rig is undergoing required inspections. The ATWOOD HUNTER is expected to be off dayrate for ten to fourteen days in December 2006 for required regulatory inspections and maintenance. Operating costs during this period could average between $60,000 and $65,000 per day. We expect that the ATWOOD FALCON will incur average daily operating costs between $45,000 and $50,000 while working offshore Malaysia; however, costs will be significantly higher during the first quarter of fiscal year 2007 ($85,000 to $95,000 per day) due to expensing certain costs incurred during the period the rig was in the shipyard undergoing its water depth upgrade. The ATWOOD SOUTHERN CROSS is also expected to have average daily operating costs in the Black Sea between $45,000 and $50,000; however, during the rig's relocation to the Black Sea during October 2006, operating costs were expected to average around $60,000 per day. Operating costs for our bottom supported drilling units (ATWOOD BEACON, VICKSBURG, and RICHMOND) should average between $30,000 and $35,000 per day. The SEAHAWK is expected to incur operating costs between $60,000 and $65,000 per day while working offshore Equatorial Guinea; however, these figures include an approximate $16,000 per day amortization of certain deferred costs on a straight-line basis over the life of the applicable drilling contract which will be more than offset by the amortization of related deferred fees of approximately $19,000 per day which are also recognized and earned on a straight-line basis over the life of the contract. Operating costs will vary for all rigs depending upon each rig's specific operating activities. For example, cost may increase when a rig is being relocated to a new drilling location, when a rig is undergoing required inspection or when a rig is undergoing extraordinary maintenance or equipment replacement. Despite the increase in operating costs for fiscal year 2006, our operating results significantly increased for fiscal year 2006 compared to fiscal year 2005. Although we anticipate a continuing trend for increases in operating costs during the next fiscal year, with our backlog of contracted days providing increasing revenue expectations, we anticipate that revenues, operating cash flows and earnings for fiscal years 2007 and 2008 will reflect a significant improvement over fiscal year 2006 operating results and are expected to be the highest in our history. RESULTS OF OPERATIONS Fiscal Year 2006 Versus Fiscal Year 2005 Revenues for fiscal year 2006 increased 57% compared to the prior fiscal year. A comparative analysis of revenues by rig for fiscal years 2006 and 2005 is as follows: REVENUES (In millions) ----------------------------------- Fiscal Fiscal 2006 2005 Variance -------- -------- --------- ATWOOD HUNTER $ 62.8 $ 22.1 $ 40.7 ATWOOD SOUTHERN CROSS 29.9 10.8 19.1 ATWOOD EAGLE 47.0 34.6 12.4 RICHMOND 20.2 11.9 8.3 ATWOOD BEACON 32.1 24.2 7.9 AUSTRALIA MANAGEMENT CONTRACTS 12.9 5.2 7.7 VICKSBURG 30.0 23.6 6.4 ATWOOD FALCON 30.1 29.8 0.3 SEAHAWK 11.6 13.9 (2.3) ------ ------ ------ $276.6 $176.1 $100.5 ====== ====== ====== 10 The increase in fleetwide revenues is primarily attributable to the increase in average dayrates due to improving market conditions and strong demand for offshore drilling equipment as noted in Market Outlook. Thus, unless otherwise noted below, the increase in revenues for each rig is due to the increases in contractual dayrates in fiscal year 2006 compared to fiscal year 2005. During the last quarter of fiscal year 2005, the ATWOOD SOUTHERN CROSS was relocated from Southeast Asia to the Mediterranean Sea with no revenues being realized during this relocation period. This relocation resulted in earned mobilization fees for the ATWOOD SOUTHERN CROSS increasing from $0.8 million in fiscal year 2005 to $8.1 million in fiscal year 2006, which, along with increases in contracted dayrates accounts for its increase in revenues. Increases in revenues for the ATWOOD HUNTER, ATWOOD EAGLE, VICKSBURG, ATWOOD BEACON, ATWOOD FALCON and the RICHMOND were related to each of these drilling units working under higher dayrate contracts in fiscal year 2006 compared to fiscal year 2005. The increase in revenues from the AUSTRALIA MANAGEMENT CONTRACTS was due to one of these managed rigs returning to active drilling. The decline in revenues for the SEAHAWK was due to the unit being upgraded in fiscal year 2006, with no revenues being realized during this upgrade period. Contract drilling costs for fiscal year 2006 increased 40% compared to the prior fiscal year. A comparative analysis of contract drilling costs by rig for fiscal years 2006 and 2005 is as follows: CONTRACT DRILLING COSTS (In millions) ------------------------------------ Fiscal Fiscal 2006 2005 Variance ------- ------- -------- ATWOOD SOUTHERN CROSS $ 24.2 $ 9.1 $ 15.1 ATWOOD HUNTER 18.8 11.9 6.9 AUSTRALIA MANAGEMENT CONTRACTS 10.8 4.7 6.1 ATWOOD EAGLE 26.8 21.9 4.9 VICKSBURG 11.9 8.8 3.1 ATWOOD BEACON 10.4 8.5 1.9 ATWOOD FALCON 16.5 14.6 1.9 RICHMOND 10.4 8.9 1.5 SEAHAWK 8.4 9.9 (1.5) OTHER 6.2 4.5 1.7 ------ ------ ------ $144.4 $102.8 $ 41.6 ====== ====== ====== The increase in fleetwide drilling costs was primarily attributable to four areas: rising personnel costs due to wage increases, increased repairs and maintenance expenses and freight costs due to the amount and timing of various repairs and maintenance projects and equipment enhancements and rising insurance costs due to increased premiums. Thus, unless otherwise noted below, the increase in drilling costs for each rig is primarily due to the four areas mentioned above. 11 Besides the four areas discussed above, the increase in drilling costs for the ATWOOD SOUTHERN CROSS is also due to $8.6 million of mobilization expense amortization during the fiscal year 2006, compared to $0.8 million of deferred mobilization expense during fiscal year 2005 as the rig relocated from Southeast Asia to the Mediterranean during the fourth quarter of fiscal year 2005. The increase in drilling costs for the ATWOOD HUNTER also includes higher agent commissions due to increased revenues when compared to the prior fiscal year and due to its relocation from Egypt to Mauritania where operating costs are higher. As previously mentioned, one of our managed platform rigs in Australia commenced a new drilling program during the current fiscal year, and thus, service activities for our AUSTRALIA MANAGEMENT CONTRACTS for fiscal year 2006 have increased accordingly when compared to fiscal year 2005. The decrease in drilling costs for the SEAHAWK is due to $4.0 million of deferred mobilization costs for fiscal year 2006 due to the relocation of the rig from Southeast Asia to West Africa compared to no deferred mobilization costs in the prior fiscal year. Other drilling costs for fiscal year 2006 have increased primarily due to the recording of stock option compensation expense (resulting from adoption of Statement of Financial Accounting Standards No. 123(R), "Share-Based Payment", or SFAS 123(R) on October 1, 2005) for field personnel. Depreciation expense for fiscal year 2006 decreased 1% as compared to the prior fiscal year. A comparative analysis of depreciation expense by rig for fiscal years 2006 and 2005 is as follows: DEPRECIATION EXPENSE (In millions) ------------------------------- Fiscal Fiscal 2006 2005 Variance ------ ------ -------- SEAHAWK $ 1.6 $ 0.5 $ 1.1 ATWOOD HUNTER 5.4 5.3 0.1 VICKSBURG 2.8 2.7 0.1 ATWOOD BEACON 5.3 5.2 0.1 RICHMOND 0.9 0.9 - ATWOOD FALCON 2.8 2.8 - ATWOOD EAGLE 4.6 4.7 (0.1) ATWOOD SOUTHERN CROSS 2.9 4.5 (1.6) OTHER 0.1 0.1 - ----- ----- ----- $26.4 $26.7 $(0.3) ===== ===== ===== The increase in depreciation expense for the SEAHAWK was due to the completion of a $16 million life enhancing upgrade during the fourth quarter of the current fiscal year. During the first quarter of the current fiscal year, the ATWOOD SOUTHERN CROSS underwent a life enhancing upgrade whereby the useful life of the rig was extended from approximately two to five years. Depreciation expense for our other units was relatively unchanged in fiscal year 2006 as compared to fiscal year 2005. In October 2005, we sold our semisubmersible hull, SEASCOUT, for $10 million (net after certain expenses) and our spare 15,000 P.S.I. BOP Stack for approximately $15 million. For the 2006 fiscal year period, gains on the sales of these two assets and other excess equipment totaled approximately $10.5 million in the aggregate. We had no operations or revenues associated with these assets prior to their sale. General and administrative expenses for fiscal year 2006 have increased 45% compared to the prior fiscal year due primarily to the following: $3.7 million of stock option compensation expense (resulting from adoption of SFAS 123(R) on October 1, 2005), a $1.5 million increase in professional fees primarily related to higher Sarbanes-Oxley compliance costs, and a $0.6 million increase in annual bonus compensation. Interest expense has decreased primarily due to the reduction of our outstanding debt while interest income has increased when compared to the prior fiscal year due to higher interest rates earned on higher cash balances. Virtually all of our tax provision for fiscal year 2006 relates to taxes in foreign jurisdictions. As a result of working in foreign jurisdictions, we earned a high level of operating income in certain nontaxable and deemed profit tax jurisdictions which significantly reduced our effective tax rate for the current fiscal year when compared to the United States statutory rate. In addition, we reversed a $1.8 million tax contingent liability due to the 12 expiration of the statute of limitations in a foreign jurisdiction. Also, we were advised by a foreign tax authority that it had approved acceptance of certain amended prior year tax returns. The acceptance of these amended tax returns, along with the fiscal year 2005 tax return in this foreign jurisdiction, resulted in the recognition of a $4.6 million tax benefit in the third quarter. Including the two previously mentioned discrete items, which reduced our rate by 7%, our effective tax rate for fiscal year 2006 was approximately 6%. Excluding any discrete items that may occur, we expect our effective tax rate to be approximately 15-20% for fiscal year 2007 due to increased earnings in foreign jurisdictions with high statutory tax rates. Fiscal Year 2005 Versus Fiscal Year 2004 Revenues for fiscal year 2005 increased 8% compared to the fiscal year 2004. A comparative analysis of revenues by rig for fiscal years 2005 and 2004 is as follows: REVENUES (In millions) ----------------------------------- Fiscal Fiscal 2005 2004 Variance ------- -------- -------- ATWOOD EAGLE $ 34.6 $ 30.4 $ 4.2 ATWOOD FALCON 29.8 26.0 3.8 ATWOOD BEACON 24.2 20.7 3.5 AUSTRALIA MANAGEMENT CONTRACTS 5.2 2.0 3.2 ATWOOD HUNTER 22.1 19.4 2.7 RICHMOND 11.9 9.6 2.3 VICKSBURG 23.6 24.3 (0.7) ATWOOD SOUTHERN CROSS 10.8 12.5 (1.7) SEAHAWK 13.9 18.6 (4.7) ------ ------ ------ $176.1 $163.5 $ 12.6 ====== ====== ====== During fiscal year 2005, the ATWOOD EAGLE was fully utilized at dayrates ranging from $89,000 to $109,000 compared to approximately 90% utilization at the same dayrates during fiscal year 2004. The increase in revenues for the ATWOOD FALCON was due to the rig being fully utilized during fiscal year 2005 at an average dayrate of $82,000 compared to 90% utilization at an average dayrate of $78,000 during fiscal year 2004. The ATWOOD BEACON had average per day revenues during fiscal year 2005 of $66,000 (which includes 100 days of business interruption proceeds) compared to average per day revenues during fiscal year 2004 of $62,000 (which includes 35 days of business interruption proceeds and 30 days of zero rate downtime immediately following its July 2004 incident which damaged its legs and derrick). Refer to Note 4 to the consolidated financial statements for further discussion of the Atwood Beacon incident. Since the end of fiscal year 2001, there has been a planned break in drilling activities on the GOODWYN `A' and NORTH RANKIN `A' platform rigs during which we have provided a limited amount of maintenance services to these platform rigs. However, during fiscal year 2005, service activities for NORTH RANKIN `A' increased due to a planned drilling program to commence during fiscal year 2006. The ATWOOD HUNTER was fully utilized during fiscal year 2005 at an average dayrate of $61,000 compared to 95% utilization during fiscal year 2004 at an average dayrate of $55,000. The increase in revenue for the RICHMOND was due to an increase in the average dayrate from $26,000 during fiscal year 2004 to $33,000 during fiscal year 2005. Revenues for the VICKSBURG were relatively consistent for fiscal years 2004 and 2005 while revenues for the ATWOOD SOUTHERN CROSS declined due to a decrease in the amount of earned mobilization revenue from $4.1 million in fiscal year 2004 to $0.8 million in fiscal year 2005 as the rig relocated twice during fiscal year 2004 and only once during fiscal year 2005. This decrease was partially offset by an increase in dayrates ranging from $35,000 to $40,000 during fiscal year 2005 compared to $30,000 to $35,000 during fiscal year 2004. The SEAHAWK was fully utilized during the fiscal year 2004 at an average dayrate of $50,000 compared to 85% utilization during fiscal year 2005 at an average dayrate of $45,000. 13 Contract drilling costs for fiscal year 2005 increased 4% compared to fiscal year 2004. A comparative analysis of contract drilling costs by rig for fiscal years 2005 and 2004 is as follows: CONTRACT DRILLING COSTS (In millions) ----------------------------------- Fiscal Fiscal 2005 2004 Variance ------- ------- -------- AUSTRALIA MANAGEMENT CONTRACTS $ 4.7 $ 2.1 $ 2.6 ATWOOD EAGLE 21.9 20.7 1.2 RICHMOND 8.9 7.9 1.0 SEAHAWK 9.9 9.0 0.9 VICKSBURG 8.8 8.3 0.5 ATWOOD HUNTER 11.9 12.0 (0.1) ATWOOD FALCON 14.6 15.1 (0.5) ATWOOD BEACON 8.5 10.2 (1.7) ATWOOD SOUTHERN CROSS 9.1 12.3 (3.2) OTHER 4.5 1.3 3.2 ------ ------ ----- $102.8 $ 98.9 $ 3.9 ====== ====== ===== With the increase in service activities for NORTH RANKIN `A' during fiscal year 2005 due to a planned drilling program to commence during fiscal year 2006, drilling costs as well as revenues increased from our management of this platform rig. The increase in drilling costs for the ATWOOD EAGLE was due to higher labor costs due to local operating requirements offshore Australia, its location for all of the fiscal year 2005. The increase in drilling costs for the RICHMOND and SEAHAWK were primarily due to higher repair and maintenance expenses incurred on the rigs during the fiscal year ended September 30, 2005 compared to the fiscal year ended September 30, 2004. Drilling costs for the VICKSBURG, ATWOOD HUNTER, and ATWOOD FALCON remained relatively consistent for fiscal year 2005 compared to fiscal year 2004. The decline in drilling costs for the ATWOOD BEACON was due to a decrease in repair and maintenance expenses primarily resulting from the recording of a $1.0 million insurance deductible during fiscal year 2004 related to damage incurred during the rig's July 2004 incident. During most of the fourth quarter of fiscal year 2005, the ATWOOD SOUTHERN CROSS was being mobilized from Southeast Asia to the Mediterranean. Virtually all costs incurred during a mobilization period are deferred and amortized as an expense over the term of the new contract. Having deferred mobilization costs at the end of fiscal year 2005 compared to having no such deferred costs at the end of fiscal year 2004 accounts for its decline in drilling costs. The increase of other drilling costs during fiscal year 2005 was due to a $1.0 million reduction in the amount of insurance premium refunds received during fiscal year 2005 when compared to fiscal year 2004 and also due to fiscal year 2004 including the settlement of a dispute with a client which resulted in a reduction of operation costs of $0.6 million along with various other increases of non-drilling unit specific costs. 14 Depreciation expense for fiscal year 2005 decreased 16% as compared to fiscal year 2004. A comparative analysis of depreciation expense by rig for fiscal years 2005 and 2004 is as follows: DEPRECIATION EXPENSE (In millions) -------------------------------- Fiscal Fiscal 2005 2004 Variance ------- ------- -------- ATWOOD SOUTHERN CROSS $ 4.5 $ 4.2 $ 0.3 VICKSBURG 2.7 2.6 0.1 ATWOOD FALCON 2.8 2.7 0.1 ATWOOD BEACON 5.2 5.2 - RICHMOND 0.9 0.9 - ATWOOD EAGLE 4.7 4.8 (0.1) ATWOOD HUNTER 5.3 5.4 (0.1) SEAHAWK 0.5 5.1 (4.6) OTHER 0.1 0.7 (0.6) ----- ----- ----- $26.7 $31.6 $(4.9) ===== ===== ===== Effective October 1, 2004, we extended the remaining depreciable life of the SEAHAWK from 2 months to 5 years. The depreciable life of this rig was extended based upon entry into a contract that extended the rig's commercial viability for up to 5 years, coupled with our intent to continue marketing and operating the rig beyond 2 months. The decrease in other depreciation is due to certain non-rig assets becoming fully depreciated during the last quarter of fiscal year 2004 and the first quarter of fiscal year 2005. Depreciation expense for our other units was relatively unchanged in fiscal year 2005 as compared to fiscal year 2004. General and administrative expenses for fiscal year 2005 increased 25% compared to fiscal year 2004 due to significantly increased professional fees primarily resulting from compliance requirements of the Sarbanes-Oxley Act and due to $0.7 million of bonuses paid during fiscal year 2005, compared with no bonus payments during fiscal year 2004. Although the level of our outstanding debt has been reduced significantly from fiscal year 2004, the reduction of interest expense was partially offset by rising interest rates during fiscal year 2005. Interest income has increased when compared to fiscal year 2004 due to higher interest rates earned on cash balances and interest income earned on income tax refunds. Virtually all of our tax provision for fiscal years 2005 and 2004 related to taxes in foreign jurisdictions, with fiscal year 2005 also impacted by a $3.3 million United States tax benefit recognized. During fiscal year 2005 our provision was also offset by two other foreign discrete items. During the first quarter of fiscal year 2005, we received a $1.7 million tax refund in Malaysia related to a previously reserved tax receivable. In addition, a $1.0 million deferred tax benefit was recognized in June 2005 due to the filing and subsequent acceptance by the local tax authority, of amended prior year tax returns. On December 1, 2005, we received notification from the United States Department of Treasury that a previously reserved United States income tax refund we had been pursuing for over two years had been approved for payment. Based upon this approval, we reduced our income tax provision by the refund amount of $3.3 million for the year ended September 30, 2005. Furthermore, during fiscal year 2005, operating income earned in certain nontaxable and deemed profit tax jurisdictions was higher when compared to fiscal year 2004, including business interruption proceeds earned by the ATWOOD BEACON in a zero tax jurisdiction for approximately three and a half months, which contributed to our lower effective tax rate. As a result of these items, our effective tax rate for fiscal year 2005 was significantly less when compared to fiscal year 2004 and the United States statutory rate. 15 LIQUIDITY AND CAPITAL RESOURCES Since we operate in a very cyclical industry, maintaining high equipment utilization in up, as well as down, cycles is a key factor in generating cash to satisfy current and future obligations. For fiscal years 2001 through 2005, net cash provided by operating activities ranged from a low of approximately $13.7 million in fiscal year 2003 to a high of approximately $62.3 million in fiscal year 2001 compared to net cash provided by operating activities of approximately $85.5 million for fiscal year 2006. Our operating cash flows are primarily driven by our operating income, which reflects dayrates and rig utilization. The low level of net cash provided by operating activities in fiscal year 2003 was due to a downturn in market conditions during which we pursued short-term contract opportunities in high operating cost areas in order to maintain high utilization of our fleet. Operating results in fiscal years 2004, 2005 and 2006 reflected continuing improvements in market conditions which enabled us to have higher cash flows and earnings in these years compared to fiscal year 2003. Due to the significant increase in future dayrate commitments at historically high levels, we have pursued longer-term contract opportunities for some of our drilling units. We currently have approximately 95% and 80% of our available operating rig days committed for fiscal years 2007 and 2008, respectively. With the current historically high dayrate commitments on all eight of our actively owned drilling units, we anticipate significant improvement in cash flows and earnings during fiscal years 2007 and 2008. Other than our expected capital expenditures of $110 million to $115 million for fiscal year 2007, the only additional cash commitment for fiscal year 2007, outside of funding current rig operations, is our required quarterly repayments under the term portion of our senior secured credit facility which will total $36 million for fiscal year 2007. We expect to generate more than sufficient cash flows from operations to satisfy all of these obligations. In October 2004, we sold in a public offering 2,350,000 shares of our common stock at an effective net price (before expenses) of $22.92 for net proceeds of approximately $53.6 million. We used these proceeds and cash on hand to repay the $55 million outstanding under the revolving portion of our credit facility. As of September 30, 2006, we only had $54 million outstanding under the term portion of our credit facility, with $10 million (repaid in October 2006) outstanding under the revolving portion of our credit facility. Our total debt to capitalization ratio (debt/(debt + equity)) is 12% as of September 30, 2006. This ratio will continue to decline unless we identify an acceptable growth opportunity. However, we will continue to explore opportunities for value enhancing growth as they arise. We are in compliance with all financial covenants at September 30, 2006 and expect to remain in compliance with all financial covenants during fiscal year 2007. Further, at all times during fiscal year 2004, 2005 and 2006 when we were required to determine compliance with our financial covenants, we were in compliance with those covenants. Aside from the financial covenants, no other provisions exist in the credit facility that could result in acceleration of the April 1, 2008 maturity date. At September 30, 2006, the collateral for our credit facility consists primarily of preferred mortgages on all eight of our active drilling units (with an aggregate net book value at September 30, 2006 totaling approximately $397 million). We are not required to maintain compensating balances; however, we are required to pay a fee of approximately 0.60% per annum on the unused revolving portion of our credit facility and certain other administrative costs. In October 2005, we sold our semisubmersible hull, SEASCOUT, for $10 million (net after certain expenses) and our spare 15,000 P.S.I. BOP Stack for approximately $15 million. For the 2006 fiscal year period, gains on the sales of these two assets and other excess equipment totaled approximately $10.5 million in the aggregate. The approximate $26 million in cash received from the sales of excess equipment, plus borrowings under the revolving portion of our credit facility ($10 million outstanding at September 30, 2006) along with our operating cash flows, has allowed us to expend approximately $30 million toward the construction of the ATWOOD AURORA, approximately $16 million on upgrading the SEAHAWK, approximately $5 million in completing the ATWOOD SOUTHERN CROSS upgrade, approximately $16 million toward the ATWOOD FALCON upgrade and approximately $11 million in other capital expenditures during fiscal year 2006 and have cash and cash equivalents remaining on hand at September 30, 2006 of approximately $32 million. 16 Our accounts receivable have increased by $40.4 million since September 30, 2005, primarily due to our increased rig utilization and higher dayrates. Our portfolio of accounts receivable is comprised of major international corporate entities with stable payment experience. Historically, we have not encountered significant difficulty in collecting receivables and typically do not require collateral for our receivables; however, we have a $0.8 million allowance for doubtful accounts at September 30, 2006. The insurance receivable of $0.6 million at September 30, 2005 and September 30, 2006, relates to repairs to be made to the ATWOOD BEACON. Final repairs on this rig were completed in November 2006, and we expect to collect the remaining $0.6 million insurance receivable associated therewith in fiscal year 2007. Long-term deferred credits have increased by $22.3 million since September 30, 2005, primarily due to deferred fees associated with the current fiscal year upgrades and mobilizations of the ATWOOD FALCON and SEAHAWK. COMMITMENTS The following table summarizes our obligations and commitments (in thousands) at September 30, 2006: Fiscal Fiscal Fiscal Fiscal Fiscal 2011 and 2007 2008 2009 2010 thereafter ------ ------ ------ ------ ---------- Long-Term Debt (1) $36,000 $28,000 $ - $ - $ - Purchase Commitments (2) 61,854 28,282 - - - Operating Leases 1,916 1,102 978 845 3,570 ------- ------- ----- ----- ------- $99,770 $57,384 $ 978 $ 845 $ 3,570 ======= ======= ===== ===== ======= (1) Excluded from the above table is interest associated with borrowings under our credit facility because the applicable interest rate is variable. The principal amount outstanding under our credit facility included in the above table is $64 million which currently bears interest at a rate of approximately 7%. (2) Rig construction and upgrade commitments for the ATWOOD AURORA and the ATWOOD FALCON, respectively. CRITICAL ACCOUNTING POLICIES Significant accounting policies are included in Note 2 to our consolidated financial statements for the year ended September 30, 2006. These policies, along with the underlying assumptions and judgments made by management in their application, have a significant impact on our consolidated financial statements. We identify our most critical accounting policies as those that are the most pervasive and important to the portrayal of our financial position and results of operations, and that require the most difficult, subjective and/or complex judgments by management regarding estimates about matters that are inherently uncertain. Our most critical accounting policies are those related to revenue recognition, property and equipment, impairment of assets, income taxes, and employee stock-based compensation. We account for the drilling and management contract revenue in accordance with the terms of the underlying drilling or management contract. These contracts generally provide that revenue is earned and recognized on a daily rate (i.e. "dayrate") basis and dayrates are typically earned for a particular level of service over the life of a contract. Dayrate contracts can be for a specified period of time or the time required to drill a specified well or number of wells. Revenues from dayrate drilling operations, which are classified under contract drilling services, are recognized on a per day basis as the work progresses. In addition, lump-sum fees received at commencement of the drilling contract as compensation for the cost of relocating drilling rigs from one major operating area to another, as well as equipment and upgrade costs reimbursed by the customer are recognized as earned on a straight-line method over the term of the related drilling contract, as are the dayrates associated with such contract. However, lump-sum fees received upon termination of a drilling contract are recognized as earned during the period termination occurs. In addition, we defer the mobilization costs relating to moving a drilling rig to a new area and customer requested equipment purchases that will revert to the customer at the end of the applicable drilling contract. We amortize such costs on a straight-line basis over the life of the applicable drilling contract. 17 We currently operate eight active offshore drilling units. These assets are premium equipment and should provide many years of quality service. At September 30, 2006, the carrying value of our property and equipment totaled $436.2 million, which represents 73% of our total assets. This carrying value reflects the application of our property and equipment accounting policies, which incorporate estimates, assumptions and judgments by management relative to the useful lives and salvage values of our units. Once a rig is placed in service, it is depreciated on the straight-line method over its estimated useful life, with depreciation discontinued only during the period when a drilling unit is out of service while undergoing a significant upgrade that extends its useful life. The estimated useful lives of our drilling units and related equipment range from 3 years to 25 years and our salvage values are generally based on 5% of capitalized costs. Any future increases in our estimates of useful lives or salvage values will have the effect of decreasing future depreciation expense in future years and spreading the expense to later years. Any future decreases in our useful lives or salvage values will have the effect of accelerating future depreciation expense. We evaluate the carrying value of our property and equipment when events or changes in circumstances indicate that the carrying value of such assets may be impaired. Asset impairment evaluations are, by nature, highly subjective. Operations of our drilling equipment are subject to the offshore drilling requirements of oil and gas exploration and production companies and agencies of foreign governments. These requirements are, in turn, subject to fluctuations in government policies, world demand and price for petroleum products, proved reserves in relation to such demand and the extent to which such demand can be met from onshore sources. The critical estimates which result from these dynamics include projected utilization, dayrates, and operating expenses, each of which impact our estimated future cash flows. Over the last ten years, our equipment utilization rate has averaged approximately 90%; however, if a drilling unit incurs significant idle time or receives dayrates below operating costs, its carrying value could become impaired. The estimates, assumptions and judgments used by management in the application of our property and equipment and asset impairment policies reflect both historical experience and expectations regarding future industry conditions and operations. The use of different estimates, assumptions and judgments, especially those involving the useful lives of our rigs and vessels and expectations regarding future industry conditions and operations, would likely result in materially different carrying values of assets and results of operations. We conduct operations and earn income in numerous foreign countries and are subject to the laws of taxing jurisdictions within those countries, as well as United States federal and state tax laws. At September 30, 2006, we have a $16.0 million net deferred income tax liability. This balance reflects the application of our income tax accounting policies in accordance with statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes". Such accounting policies incorporate estimates, assumptions and judgments by management relative to the interpretation of applicable tax laws, the application of accounting standards, and future levels of taxable income. The estimates, assumptions and judgments used by management in connection with accounting for income taxes reflect both historical experience and expectations regarding future industry conditions and operations. Changes in these estimates, assumptions and judgments could result in materially different provisions for deferred and current income taxes. Effective October 1, 2005, we adopted Statement of Financial Accounting Standards No. 123(R), "Share-Based Payment", or SFAS 123(R), using the modified prospective application transition method. Under this method, stock-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the requisite service period (generally the vesting period of the equity grant). In addition, stock-based compensation cost recognized includes compensation cost for unvested stock-based awards as of October 1, 2005. Prior to October 1, 2005, we accounted for share-based compensation in accordance with Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees", or APB No. 25. No share-based employee compensation cost has been reflected in net income prior to October 1, 2005. Before that date, we reported the entire tax benefit related to the exercise of stock options as an operating cash flow. SFAS 123(R) requires us to report the tax benefit from the tax deduction that is in excess of recognized compensation costs (excess tax benefits) as a financing cash flow rather than as an operating cash flow. The cumulative effect of the change in accounting principle from APB No. 25 to FAS 123(R) was not material. 18 RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS In June 2006, the FASB issued FIN 48, "Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement 109." FIN 48 prescribes a comprehensive model for recognizing, measuring, presenting, and disclosing uncertain tax positions within the financial statements. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006. We are currently evaluating the impact of the adoption of FIN 48 on our consolidated financial position, results of operations and cash flows. In September 2005, the FASB issued SFAS No. 157, "Fair Value Measurements", or SFAS No. 157, which defines fair value, establishes methods used to measure fair value and expands disclosure requirements about fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal year beginning after November 15, 2007, and interim periods within those fiscal periods. We are currently analyzing the provisions of SFAS No. 157 and determining how it will affect accounting policies and procedures, but we have not yet made a determination of the impact the adoption will have on our consolidated financial position, results of operations and cash flows. In September 2006, the SEC issued Staff Accounting Bulletin No. 108, "Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements", or SAB 108, which provides guidance on the consideration of the effects of prior year misstatements in quantifying current year misstatements for the purpose of a materiality assessment. SAB 108 requires that the materiality of the effect of a misstated amount be evaluated on each financial statement and the related financial statement disclosures, and that materiality evaluation be based on quantitative and qualitative factors. SAB 108 is effective for fiscal years beginning after November 15, 2006. We do not believe this guidance will have a material impact on our financial position, results of operations or cash flows. DISCLOSURES ABOUT MARKET RISK We are exposed to market risk, including adverse changes in interest rates and foreign currency exchange rates as discussed below. Interest Rate Risk All of the $64 million of long-term debt outstanding at September 30, 2006, was floating rate debt. As a result, our annual interest costs in fiscal year 2006 will fluctuate based on interest rate changes. Because the interest rate on our long-term debt is a floating rate and due to our debt maturing in 2008, the fair value of our long-term debt approximated carrying value as of September 30, 2006. The impact on annual cash flow of a 10% change in the floating rate (approximately 70 basis points) would be approximately $0.4 million, which we believe to be immaterial. We did not have any open derivative contracts relating to our floating rate debt at September 30, 2006. Foreign Currency Risk Certain of our subsidiaries have monetary assets and liabilities that are denominated in a currency other than their functional currencies. Based on September 30, 2006 amounts, a decrease in the value of 10% in the foreign currencies relative to the United States dollar from the year-end exchange rates would result in a foreign currency transaction gain of approximately $0.2 million. Thus, we consider our current risk exposure to foreign currency exchange rate movements, based on net cash flows, to be immaterial. We did not have any open derivative contracts relating to foreign currencies at September 30, 2006. 19 MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING Company management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Our internal control over financial reporting was designed by management, under the supervision of the Chief Executive Officer and Chief Financial Officer, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States, and 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 accounting principles generally accepted in the United States, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) 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 and procedures may deteriorate. Management assessed the effectiveness of the Company's internal control over financial reporting as of September 30, 2006. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on our evaluation under the framework in Internal Control-Integrated Framework, management has concluded that the Company maintained effective internal control over financial reporting as of September 30, 2006. PricewaterhouseCoopers LLP, our independent registered public accounting firm, has audited our assessment of the effectiveness of the Company's internal control over financial reporting as of September 30, 2006, as stated in their report which appears on the following page. ATWOOD OCEANICS, INC. by /s/ John R. Irwin /s/ James M. Holland John R. Irwin James M. Holland Director, President Senior Vice President and and Chief Executive Officer Chief Financial Officer December 12, 2006 20 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM The Board of Directors and Shareholders of Atwood Oceanics, Inc. We have completed integrated audits of Atwood Oceanics, Inc.'s 2006 and 2005 consolidated financial statements and of its internal control over financial reporting as of September 30, 2006 and an audit of its 2004 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below. Consolidated financial statements In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of cash flows and of changes in shareholders' equity present fairly, in all material respects, the financial position of the Company at September 30, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2006 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements 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 of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. As discussed in Note 3 to the consolidated financial statements, in 2006 the Company changed its method of accounting for share-based compensation as a result of adopting the provisions of Statement of Financial Accounting Standards No. 123(R), "Share-Based Payment." Internal control over financial reporting Also, in our opinion, management's assessment, included in the accompanying Management's Report on Internal Control Over Financial Reporting, which appears on the preceding page, that the Company maintained effective internal control over financial reporting as of September 30, 2006 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2006, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Company'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 opinions on management's assessment and on the effectiveness of the Company's internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting 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. An audit of internal control over financial reporting includes 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 consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions. 21 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 (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 authorizations of management and directors of the company; and (iii) 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. PricewaterhouseCoopers LLP /s/PricewaterhouseCoopers LLP Houston, Texas December 12, 2006 22 CONSOLIDATED BALANCE SHEETS Atwood Oceanics, Inc. and Subsidiaries September 30, - ------------------------------------------------------------------------------------------------- (In thousands) 2006 2005 - ------------------------------------------------------------------------------------------------- ASSETS CURRENT ASSETS: Cash and cash equivalents $ 32,276 $ 18,982 Accounts receivable, net of an allowance of $750 and $189 at September 30, 2006 and 2005, respectively 80,222 39,865 Income tax receivable 65 3,278 Insurance receivable 550 550 Inventories of materials and supplies 22,124 15,640 Deferred tax assets 2,563 3,080 Prepaid expenses and deferred costs 9,873 10,658 --------- --------- Total Current Assets 147,673 92,053 --------- --------- NET PROPERTY AND EQUIPMENT 436,166 390,778 ASSET HELD FOR SALE - 9,017 DEFERRED COSTS AND OTHER ASSETS 9,990 3,846 --------- --------- $ 593,829 $ 495,694 ========= ========= LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Current maturities of notes payable $ 36,000 $ 36,000 Accounts payable 11,760 6,473 Accrued liabilities 13,201 11,088 Deferred credits 404 2,598 --------- --------- Total Current Liabilities 61,365 56,159 --------- --------- LONG-TERM DEBT, net of current maturities: 28,000 54,000 --------- --------- 28,000 54,000 --------- --------- LONG TERM LIABILITIES: Deferred income taxes 18,591 20,140 Deferred credits 23,284 994 Other 3,695 2,264 --------- --------- 45,570 23,398 --------- --------- COMMITMENTS AND CONTENGENCIES (SEE NOTE 11) SHAREHOLDERS' EQUITY: Preferred stock, no par value; 1,000 shares authorized, none outstanding - - Common stock, $1 par value, 50,000 shares authorized with 31,046 and 30,682 issued and outstanding at September 30, 2006 and 2005, respectively (1) 31,046 30,682 Paid-in capital (1) 115,916 105,645 Retained earnings 311,932 225,810 --------- --------- Total Shareholders' Equity 458,894 362,137 --------- --------- $ 593,829 $ 495,694 ========= =========
The accompanying notes are an integral part of these consolidated financial statements. (1) Fiscal year 2005 balances have been restated to reflect a two-for-one stock split effected on March 2, 2006. See Note 7 for further discussion. 23 Atwood Oceanics, Inc. and Subsidiaries CONSOLIDATED STATEMENTS OF OPERATIONS Years Ended September 30, - ----------------------------------------------------------------------------------------------------------- (In thousands, except per share amounts) 2006 2005 2004 - ----------------------------------------------------------------------------------------------------------- REVENUES: Contract drilling $276,625 $168,500 $161,074 Business interruption proceeds - 7,656 2,380 -------- -------- -------- 276,625 176,156 163,454 COSTS AND EXPENSES: Contract drilling 144,366 102,849 98,936 Depreciation 26,401 26,735 31,582 General and administrative 20,630 14,245 11,389 Gain on sale of equipment (10,548) - - -------- -------- -------- 180,849 143,829 141,907 -------- -------- -------- OPERATING INCOME 95,776 32,327 21,547 -------- -------- -------- OTHER INCOME (EXPENSE): Interest expense, net of capitalized interest (5,166) (7,352) (9,202) Interest income 1,226 633 57 -------- -------- -------- (3,940) (6,719) (9,145) -------- -------- -------- INCOME BEFORE INCOME TAXES 91,836 25,608 12,402 PROVISION (BENEFIT) FOR INCOME TAXES 5,714 (403) 4,815 -------- -------- -------- NET INCOME $ 86,122 $ 26,011 $ 7,587 ======== ======== ======== EARNINGS PER COMMON SHARE (1): Basic $ 2.78 $ 0.86 $ 0.27 Diluted 2.74 0.83 $ 0.27 AVERAGE COMMON SHARES OUTSTANDING (1) : Basic 30,936 30,412 27,718 Diluted 31,442 31,220 28,064
The accompanying notes are an integral part of these consolidated financial statements. (1) Fiscal years 2005 and 2004 have been restated to reflect a two-for-one stock split effected on March 2, 2006. See Note 7 for further discussion. Atwood Oceanics, Inc. and Subsidiaries CONSOLIDATED STATEMENTS OF CASH FLOWS For Years Ended September 30, - -------------------------------------------------------------------------------------------------------------------------- (In thousands) 2006 2005 2004 - -------------------------------------------------------------------------------------------------------------------------- CASH FLOW FROM OPERATING ACTIVITIES: Net income $ 86,122 $ 26,011 $ 7,587 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation 26,401 26,735 31,582 Amortization of debt issuance costs 804 804 711 Amortization of deferred items (1,254) 292 (5,957) Provision for doubtful accounts 726 189 - Provision for inventory obsolescence - - 250 Deferred federal income tax benefit (1,032) (1,580) (2,040) Stock-based compensation expense 4,568 - - (Gain) loss on sale of assets (10,548) - 163 Changes in assets and liabilities: (Increase) decrease in accounts receivable (41,083) (7,579) 1,667 (Increase) decrease in insurance receivable - 9,133 (9,133) (Increase) decrease in income tax receivable 3,213 (3,278) - Increase in inventory (6,484) (2,839) (315) (Increase) decrease in prepaid expenses (5,061) 1,585 931 Increase in deferred costs and other assets (11,419) (10,422) (9,213) Increase (decrease) in accounts payable 5,287 (2,925) (487) Increase (decrease) in accrued liabilities 3,985 (2,734) 4,971 Increase in deferred credits and other liabilities 31,226 5,429 4,883 Tax benefit from the exercise of stock options - 2,250 75 Other 1 21 (62) -------- -------- -------- (670) 15,081 18,026 -------- -------- -------- Net Cash Provided by Operating Activities 85,452 41,092 25,613 -------- -------- -------- CASH FLOW FROM INVESTING ACTIVITIES: Capital expenditures (78,464) (25,563) (6,527) Collection of insurance receivable - 15,750 - Proceeds from sale of assets 26,239 - - -------- -------- -------- Net Cash Used by Investing Activities (52,225) (9,813) (6,527) -------- -------- -------- CASH FLOW FROM FINANCING ACTIVITIES: Proceeds from debt 20,000 10,000 - Principal payments on debt (46,000) (101,000) (24,000) Debt issuance costs paid - - (681) Proceeds from common stock offering - 53,607 - Proceeds from exercise of stock options 6,067 8,680 460 -------- -------- -------- Net Cash Provided Used by Financing Activities (19,933) (28,713) (24,221) -------- -------- -------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS $ 13,294 $ 2,566 $ (5,135) CASH AND CASH EQUIVALENTS, at beginning of period $ 18,982 $ 16,416 $ 21,551 -------- -------- -------- CASH AND CASH EQUIVALENTS, at end of period $ 32,276 $ 18,982 $ 16,416 ======== ======== ======== Supplemental disclosure of cash flow information: Cash paid during the year for domestic and foreign income taxes $ 2,654 $ 5,977 $ 5,549 ======== ======== ======== Cash paid during the year for interest, net of amounts capitalized $ 5,033 $ 7,705 $ 9,208 ======== ======== ======== Non-cash Activities: Increase in receivable related to reduction in value of the ATWOOD BEACON $ - $ - $ 16,300 ======== ======= ========
The accompanying notes are an integral part of these consolidated financial statements. 25 Atwood Oceanics, Inc. and Subsidiaries CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY - ---------------------------------------------------------------------------------------------------------------------- Total Common Stock Paid-in Retained Stockholders' (In thousands) Shares Amount Capital Earnings Equity - ---------------------------------------------------------------------------------------------------------------------- September 30, 2003 (1) 27,702 $ 27,702 $ 43,553 $192,212 $263,467 Net income - - - 7,587 7,587 Exercise of employee stock options 44 44 416 - 460 Tax benefit from exercise of employee stock options - - 75 - 75 ------ -------- -------- -------- -------- September 30, 2004 (1) 27,746 $ 27,746 $ 44,044 $199,799 $271,589 Net income - - - 26,011 26,011 Exercise of employee stock options 586 586 8,094 - 8,680 Common stock offering 2,350 2,350 51,257 - 53,607 Tax benefit from exercise of employee stock options - - 2,250 - 2,250 ------ -------- -------- -------- -------- September 30, 2005 (1) 30,682 $ 30,682 $105,645 $225,810 $362,137 Net income - - - 86,122 86,122 Restricted stock awards 5 5 (5) - - Exercise of employee stock options 359 359 5,708 - 6,067 Stock option and restricted stock award compensation expense - - 4,568 - 4,568 ------ -------- -------- -------- -------- September 30, 2006 31,046 $ 31,046 $115,916 $311,932 $458,894 ====== ======== ======== ======== ======== The accompanying notes are an integral part of these consolidated financial statements. (1) Fiscal years 2005, 2004 and 2003 have been restated to reflect a two-for-one stock split effected on March 2, 2006. See Note 7 for further discussion.
26 Atwood Oceanics, Inc. and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1 - NATURE OF OPERATIONS Atwood Oceanics, Inc., together with its subsidiaries (collectively referred to herein as "we," "our" or the "Company"), is engaged in offshore drilling and completion of exploratory and developmental oil and gas wells and related support, management and consulting services principally in international locations. Presently, we own and operate a premium, modern fleet of eight mobile offshore drilling units and manage the operations of two operator-owned platform drilling units located in Northwest Australia. Currently, we are involved in active operations in the territorial waters of Australia, Malaysia, Thailand, India, Turkey, Mauritania, Equatorial Guinea and the United States. NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Consolidation The consolidated financial statements include the accounts of Atwood Oceanics, Inc. and all of its domestic and foreign subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. Cash and cash equivalents Cash and cash equivalents consist of cash in banks and highly liquid debt instruments, which mature within three months of the date of purchase. Foreign exchange The United States dollar is the functional currency for all areas of our operations. Accordingly, monetary assets and liabilities denominated in foreign currency are converted to United States dollars at the rate of exchange in effect at the end of the fiscal year, items of income and expense are remeasured at average monthly rates, and property and equipment and other nonmonetary amounts are remeasured at historical rates. Gains and losses on foreign currency transactions and remeasurements are included in contract drilling costs in our consolidated statements of operations. We recorded a foreign exchange loss of $0.1 million during fiscal year 2006, a foreign exchange gain of $0.1 million during fiscal year 2005, and no foreign exchange gain or loss during fiscal year 2004. Accounts Receivable We record trade accounts receivable at the amount we invoice our customers. These accounts do not bear interest. Our portfolio of accounts receivable is comprised of major international corporate entities and government organizations with stable payment experience. Historically, our uncollectible accounts receivable have been immaterial, and typically, we do not require collateral for our receivables. We provide an allowance for uncollectible accounts, as necessary, on a specific identification basis. We had an allowance for doubtful accounts of $0.8 million and $0.2 million, as of September 30, 2006 and 2005, respectively. Insurance receivable We had an insurance receivable of $0.6 million as of September 30, 2006 and 2005, related to a claim filed as a result of damage sustained by the ATWOOD BEACON in July 2004 while positioning for a well offshore Indonesia. We expect to collect the remaining receivable during fiscal year 2007. See Note 4 for further discussion regarding the ATWOOD BEACON incident. Inventories of Material and Supplies Inventories consist of spare parts, material and supplies held for consumption and are stated principally at the lower of average cost or market, net of reserves for excess and obsolete inventory of $1.3 million and $1.8 million at September 30, 2006 and 2005, respectively. 27 Income taxes We account for income taxes in accordance with Statement of Financial Accounting Standards ("SFAS") No. 109 "Accounting for Income Taxes." Under SFAS No. 109, deferred income taxes are recorded to reflect the tax consequences on future years of differences between the tax basis of assets and liabilities and their financial reporting amounts at each year-end given the provisions of enacted tax laws in each respective jurisdiction. Deferred tax assets are reduced by a valuation allowance when, based upon management's estimates, it is more likely than not that a portion of the deferred tax assets will not be realized in a future period. Property and equipment Property and equipment are recorded at cost. Interest costs related to property under construction are capitalized as a component of construction costs. Interest capitalized during fiscal 2006 was $1.6 million. We had no capitalized interest during fiscal years 2005 or 2004. Once a rig is placed in service, it is depreciated on the straight-line method over its estimated useful life, with depreciation discontinued only during the period when a drilling unit is out of service while undergoing a significant upgrade that extends its useful life. Our estimated useful lives of our various classifications of assets are as follows: Years Drilling vessels and related equipment...... 5-25 Drill pipe.................................. 3 Furniture and other......................... 3-10 Maintenance, repairs and minor replacements are charged against income as incurred; major replacements and upgrades are capitalized and depreciated over the remaining useful life of the asset as determined upon completion of the work. The cost and related accumulated depreciation of assets sold, retired or otherwise disposed are removed from the accounts at the time of disposition, and any resulting gain or loss is reflected in the Consolidated Statements of Operations for the applicable period. Impairment of property and equipment We periodically evaluate our property and equipment to determine that their net carrying value is not in excess of their net realizable value. These evaluations are performed when we have sustained significant declines in utilization and dayrates and recovery is not contemplated in the near future. We consider a number of factors such as estimated future cash flows, appraisals and current market value analysis in determining an asset's fair value. Assets are written down to their fair value if the carrying amount of the asset is not recoverable and exceeds its fair value. Deferred drydocking costs We defer the costs of scheduled drydocking and charge such costs to expense over the period to the next scheduled drydocking (normally 30 months). At September 30, 2006 and 2005, deferred drydocking costs totaling $0.6 million and $0.7 million, respectively, were included in Deferred Costs and Other Assets in the accompanying Consolidated Balance Sheets. Revenue recognition We account for drilling and management contract revenue in accordance with the term of the underlying drilling or management contract. These contracts generally provide that revenue is earned and recognized on a daily basis. We provide crewed rigs to customers on a daily rate (i.e. "dayrate") basis. Dayrate contracts can be for a specified period of time or the time required to drill a specified well or number of wells. Revenues from dayrate drilling operations, which are classified under contract drilling services, are recognized on a per day basis as the work progresses. In addition, business interruption proceeds are also recognized on a per day basis. See Note 4 for further discussion of the ATWOOD BEACON incident. 28 Deferred fees and costs Lump-sum fees received at commencement of the drilling contract as compensation for the cost of relocating drilling rigs from one major operating area to another, as well as equipment and upgrade costs reimbursed by the customer are recognized as earned on a straight-line method over the term of the related drilling contract, as are the dayrates associated with such contract. However, lump-sum fees received upon termination of a drilling contract are recognized as earned during the period termination occurs. In addition, we defer the mobilization costs relating to moving a drilling rig to a new area and customer requested equipment purchases that will revert to the customer at the end of the applicable drilling contract. We amortize such costs on a straight-line basis over the life of the applicable drilling contract. Contract revenues and drilling costs are reported in the Statements of Operations at their gross amounts. At September 30, 2006 and 2005, deferred fees associated with mobilization as well as equipment purchases and upgrades totaled $23.7 million and $3.6 million, respectively. At September 30, 2006 and 2005 deferred costs associated with mobilization and equipment purchases totaled $9.0 million and $7.8 million, respectively. Deferred fees and deferred costs are classified as current or long-term in the accompanying Consolidated Balance Sheets based on the expected term of the applicable drilling contracts. Share-based compensation Effective October 1, 2005, we adopted Statement of Financial Accounting Standards No. 123(R), "Share-Based Payment", or SFAS 123(R), using the modified prospective application transition method. Under this method, stock-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the requisite service period (generally the vesting period of the equity grant). In addition, stock-based compensation cost recognized includes compensation cost for unvested stock-based awards as of October 1, 2005. Prior to October 1, 2005, we accounted for share-based compensation in accordance with Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees", or APB No. 25. No share-based employee compensation cost has been reflected in net income prior to October 1, 2005. Before that date, we reported the entire tax benefit related to the exercise of stock options as an operating cash flow. SFAS 123(R) requires us to report the tax benefit from the tax deduction that is in excess of recognized compensation costs (excess tax benefits) as a financing cash flow rather than as an operating cash flow. The cumulative effect of the change in accounting principle from APB No. 25 to SFAS 123(R) was not material. See Note 3 for additional information. Earnings per common share Basic and diluted earnings per share have been computed in accordance with SFAS No. 128, "Earnings per Share" (EPS). "Basic" EPS excludes dilution and is computed by dividing net income (loss) by the weighted-average number of common shares outstanding for the period. "Diluted" EPS reflects the issuance of additional shares in connection with the assumed conversion of stock options. Under the modified prospective application transition method of SFAS 123(R), we have included the impact of pro forma deferred tax assets in calculating the potential windfall and shortfall tax benefits to determine the amount of diluted shares using the treasury stock method. 29 The computation of basic and diluted earnings per share under SFAS No. 128 for each of the past three fiscal years is as follows (in thousands, except per share amounts): Per Share Net Income Shares Amount ---------- ------ --------- Fiscal 2006: Basic earnings per share $ 86,122 30,936 $ 2.78 Effect of dilutive securities - Stock options - 506 (0.04) -------- ------ ------ Diluted earnings per share $ 86,122 31,442 $ 2.74 ======== ====== ====== Fiscal 2005: Basic earnings per share $ 26,011 30,412 $ 0.86 Effect of dilutive securities - Stock options - 808 (0.03) -------- ------ ------ Diluted earnings per share $ 26,011 31,220 $ 0.83 ======== ====== ====== Fiscal 2004: Basic earnings per share $ 7,587 27,718 $ 0.27 Effect of dilutive securities - Stock options - 346 - -------- ------ ------ Diluted earnings per share $ 7,587 28,064 $ 0.27 ======== ====== ======
The calculation of diluted earnings per share for the years ended September 30, 2006 and 2004 excludes consideration of shares of common shares which may be issued in connection with outstanding stock options of 125,200 and 202,550, respectively, because such options were antidilutive. These options could potentially dilute basic EPS in the future. For the year ended September 30, 2005, there were no antidilutive options. Use of estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make extensive use of estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. NOTE 3 - SHARE-BASED COMPENSATION Effective October 1, 2005, we adopted SFAS 123(R), using the modified prospective application transition method. Under this method, stock-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as an expense over the requisite service period (generally the vesting period of the equity grant). In addition, stock-based compensation cost recognized includes compensation cost for unvested stock-based awards as of October 1, 2005. Prior to October 1, 2005, we accounted for share-based compensation in accordance with APB No. 25. No share-based employee compensation cost has been reflected in net income prior to October 1, 2005. Before that date, we reported the entire tax benefit related to the exercise of stock options as an operating cash flow. SFAS 123(R) requires us to report the tax benefit from the tax deduction that is in excess of recognized compensation costs (excess tax benefits) as a financing cash flow rather than as an operating cash flow. The cumulative effect of the change in accounting principle from APB No. 25 to FAS 123(R) was not material. 30 Under our Amended and Restated 2001 Stock Incentive Plan, or the 2001 Plan, up to 2,000,000 shares of common stock may be issued to eligible participants in the form of restricted stock awards or upon exercise of stock options granted pursuant to the 2001 Plan. Awards of restricted stock and grants of stock options may be made under the 2001 Plan through September 5, 2011. We also have another stock incentive plan, the 1996 Plan, under which there are outstanding stock options. However, no additional options or restricted stock will be awarded under the 1996 plan. A summary of share and stock option data for our two stock incentive plans as of September 30, 2006 is as follows: 2001 1996 Plan Plan ------- -------- Shares available for future awards or grants 755,049 102,000 Outstanding stock option grants 969,200 467,750 Outstanding unvested restricted stock awards 92,600 - Awards of restricted stock and stock options have both been granted under our stock incentive plans as of September 30, 2006. We deliver newly issued shares of common stock for restricted stock awards upon vesting and upon exercise of stock options. All stock incentive plans currently in effect have been approved by the shareholders of our outstanding common stock. For the year ended September 30, 2006, the impact of adopting SFAS 123(R) had no effect on our cash flows, however, but did have the following effect on our consolidated statements of operations (in thousands, except per share amounts): Increase in contract drilling expenses $ 840 Increase in general and administrative expenses 3,728 Decrease in income tax provision (1,305) ------ Decrease in net income 3,263 ====== Decrease in earnings per share: Basic $ 0.11 Diluted $ 0.10 We recognize compensation expense on grants of share-based compensation awards on a straight-line basis over the required service period for each award. As of September 30, 2006, unrecognized compensation cost, net of estimated forfeitures, related to stock options and restricted stock awards was approximately $4.6 million and $2.7 million, respectively, which we expect to recognize over a weighted average period of approximately 2.4 years. Stock Options Under our stock incentive plans, the exercise price of each stock option equals the fair market value of one share of our common stock on the date of grant, with all outstanding options having a maximum term of 10 years. Options vest ratably over a period from the end of the first to the fourth year from the date of grant under the 2001 Plan and from the end of the second to the fifth year from the date of grant under the 1996 Plan. Each option is for the purchase of one share of our common stock. 31 The total fair value of stock options vested during years ended September 30, 2006, 2005 and 2004 was $3.2 million, $2.9 million and $2.2 million, respectively. The per share weighted average fair value of stock options granted during years ended September 30, 2006, 2005 and 2004 was $17.87, $10.22 and $7.08, respectively. We estimated the fair value of each stock option on the date of grant using the Black-Scholes pricing model and the following assumptions: Fiscal Fiscal Fiscal 2006 2005 2004 ------ ------ ----- Risk-Free Interest Rate 4.50% 4.27% 4.38% Expected Volatility 41.62% 35.00% 50.00% Expected Life (Years) 6 6 6 Dividend Yield None None None The average risk-free interest rate is based on the five-year United States treasury security rate in effect as of the grant date. We determined expected volatility using a two to six year historical volatility figure and determined the expected term of the stock options using 15 years of historical data. The expected dividend yield is based on the expected annual dividend as a percentage of the market value of our common stock as of the grant date. A summary of stock option activity for years ended September 30, 2004, 2005 and 2006 is as follows: Wtd. Avg. Wtd. Avg. Remaining Aggregate Number of Exercise Contractual Intrinsic Options Price Life (Years) Value (000s) ---------- -------- ----------- ----------- Outstanding at October 1, 2003 1,647,150 $ 15.69 Granted 370,000 13.83 Exercised (42,800) 10.77 $ 377 Forfeited (9,000) 15.54 --------- ------- Outstanding at September 30, 2004 1,965,350 $ 15.46 6.1 $ 16,333 --------- ------- Exercisable at September 30, 2004 1,095,600 $ 15.67 4.8 $ 8,879 ========= ======= Outstanding at October 1, 2004 1,965,350 $ 15.46 Granted 340,000 25.16 Exercised (586,800) 14.69 $ 10,095 Forfeited (15,250) 17.85 --------- ------ Outstanding at September 30, 2005 1,703,300 $ 17.64 6.5 $ 42,342 --------- ------- Exercisable at September 30, 2005 934,926 $ 16.27 5.1 $ 24,527 ========= ======= Outstanding at October 1, 2005 1,703,300 $ 17.64 Granted 130,300 38.21 Exercised (359,450) 16.93 $ 10,184 Forfeited (37,200) 22.64 --------- ------ Outstanding at September 30, 2006 1,436,950 $ 19.56 6.4 $ 36,518 ========= ======= Exercisable at September 30, 2006 889,500 $ 16.61 5.3 $ 25,227 ========= =======
32 Restricted Stock We have also awarded restricted stock to certain employees and to our non-employee directors. The awards of restricted stock to employees are subject to three year vesting, and all restricted stock awards to date are restricted from transfer for three years form the date of grant. Pursuant to the amendments to our 2001 Plan approved by our shareholders on February 9, 2006, and as discussed in our definitive proxy statement sent to our shareholders relating to our annual shareholders meeting and filed with the SEC on January 13, 2006, our non-employee directors have been granted stock awards vesting immediately totaling an aggregate of 5,151 shares of our common stock as of September 30, 2006. We value restricted stock awards at fair market value of our common stock on the date of grant. A summary of restricted stock activity for the year ended September 30, 2006, is as follows: Number of Wtd. Avg. Shares Fair Value --------- ---------- Unvested at October 1, 2005 - Granted 102,151 $ 38.46 Vested (5,151) $ 46.57 Forfeited (4,400) $ 37.15 ------- Unvested at September 30, 2006 92,600 $ 38.07 ======= Prior Year Pro Forma Expense The following table illustrates the effect on net income and earnings per share as if the fair value-based method provided by SFAS 123(R) had been applied for all outstanding and unvested awards for periods prior to our adoption of SFAS 123(R) as of October 1, 2005 (in thousands, except per share amounts): Fiscal Fiscal 2005 2004 ------- ------ Net income, as reported $ 26,011 $ 7,587 Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects (1,671) (2,517) -------- ------- Pro Forma, net income $ 24,340 $ 5,070 ======== ======= Earnings per share: Basic - as reported $ 0.86 $ 0.27 Basic - pro forma $ 0.80 $ 0.18 Diluted - as reported $ 0.83 $ 0.27 Diluted - pro forma $ 0.78 $ 0.18 33 NOTE 4 - PROPERTY AND EQUIPMENT A summary of property and equipment by classification is as follows (in thousands): September 30, ------------------------- 2006 2005 ------- ------- Drilling vessels and related equipment Cost $ 691,289 $ 624,118 Accumulated depreciation (261,682) (236,736) --------- --------- Net book value 429,607 387,382 --------- --------- Drill Pipe Cost 13,271 10,742 Accumulated depreciation (8,257) (8,407) --------- --------- Net book value 5,014 2,335 --------- --------- Furniture and other Cost 7,920 7,395 Accumulated depreciation (6,375) (6,334) --------- --------- Net book value 1,545 1,061 --------- ------- NET PROPERTY AND EQUIPMENT $ 436,166 $ 390,778 ========= ========= ATWOOD BEACON - The ATWOOD BEACON incurred damage to all three legs and its derrick while positioning for a well offshore of Indonesia in July 2004. The rig and its damaged legs were transported to the builder's shipyard in Singapore for inspections and repairs. We had loss of hire insurance coverage of $70,000 per day up to 180 days, which began after a 30-day waiting period commencing July 28, 2004. Revenue recognized from this insurance coverage totaled approximately $2.4 million in fiscal year 2004 and $7.7 million in fiscal year 2005 and is reflected as business interruption proceeds on the Consolidated Statement of Operations. As of September 30, 2006 and 2005, all costs incurred to date and business interruption proceeds earned related to this incident had been reimbursed by the insurance carrier. During November 2006, we completed the remaining work to repair the rig, and we expect to collect the remaining $0.6 million insurance receivable associated therewith in fiscal year 2007. NOTE 5 - LONG-TERM DEBT A summary of long-term debt is as follows (in thousands): September 30, ------------------- 2006 2005 ------ ------ Credit facility, bearing interest (market adjustable) at approximately 7% and 5.25% per annum at September 30, 2006 and 2005, respectively $ 64,000 $ 90,000 Less - current maturities 36,000 36,000 -------- -------- $ 28,000 $ 54,000 ======== ========
34 Our $250 million senior secured credit facility consists of a 5-year $150 million amortizing term loan facility and a 5-year $100 million non-amortizing revolving loan facility. The term portion of our credit facility requires quarterly payments of $9 million until maturity on April 1, 2008. The credit facility permits prepayment of principal at anytime without incurring a penalty. At September 30, 2005, we had $90 million outstanding under the term portion of our credit facility and none outstanding under the revolving portion of our credit facility while at September 30, 2006, we had $54 million outstanding under the term portion of our credit facility and $10 million outstanding under the revolving portion of our credit facility. The collateral at September 30, 2006 for the Credit Facility consists primarily of preferred mortgages on all eight of our active drilling units (with an aggregate net book value at September 30, 2006 totaling approximately $397 million). We are not required to maintain compensating balances; however, we are required to pay a fee of approximately 0.60% per annum on the unused portion of the revolving portion of our credit facility and certain other administrative costs. The Credit Facility contains financial covenants, including but not limited to, requirements for maintaining certain net worth and other financial ratios, and restrictions on disposing of any material assets, paying cash dividends or repurchasing any of our outstanding common stock and incurring any additional indebtedness in excess of $3 million. We are in compliance with all financial covenants at September 30, 2006. Further, at all times during fiscal year 2004, 2005 and 2006 when we were required to determine compliance with our financial covenants, we were in compliance with the covenants. Aside from the financial covenants, no other provisions exist in the Credit Facility that could result in acceleration of the April 1, 2008 maturity date. The Credit Facility also supports issuance, when required, of standby letters of guarantee. At September 30, 2006, standby letters of guarantee in the aggregate amount of approximately $0.5 million were outstanding. Future maturities of long-term debt are as follows (in thousands): FISCAL YEAR AMOUNT ----------- -------- 2007 $ 36,000 2008 28,000 ---- -------- $ 64,000 ======== NOTE 6 - INCOME TAXES Domestic and foreign income before income taxes for the three-year period ended September 30, 2006 is as follows (in thousands): Fiscal Fiscal Fiscal 2006 2005 2004 ------ -------- ------- Domestic income (loss) $ 5,738 $ (45) $ 1,094 Foreign income 86,098 25,653 11,308 -------- -------- -------- $ 91,836 $ 25,608 $ 12,402 ======== ======== ======== The provision (benefit) for domestic and foreign taxes on income consists of the following (in thousands): Fiscal Fiscal Fiscal 2006 2005 2004 ------ ------ ------ Current - domestic $ 58 $(3,278) $ 277 Deferred - domestic (392) (270) (990) Current - foreign 6,688 2,205 6,578 Deferred - foreign (640) 940 (1,050) ------ ------- ------- $5,714 $ (403) $ 4,815 ====== ======= ======= 35 The components of the deferred income tax assets (liabilities) as of September 30, 2006 and 2005 are as follows (in thousands): September 30, -------------------- 2006 2005 ------ ----- Deferred tax assets - Net operating loss carryforwards $ 2,550 $ 5,900 Tax credit carryforwards 1,400 1,390 Stock option compensation expense 1,215 - Book accruals - 20 -------- -------- 5,165 7,310 -------- -------- Deferred tax liabilities - Difference in book and tax basis of equipment (20,553) (22,530) Deferred income - (1,330) -------- -------- (20,553) (23,860) -------- -------- Net deferred tax liabilities before valuation allowance (15,388) (16,550) Valuation allowance (640) (510) -------- -------- $(16,028) $(17,060) ======== ======== Net current deferred tax assets $ 2,563 $ 3,080 Net noncurrent deferred tax liabilities (18,591) (20,140) -------- -------- $(16,028) $(17,060) ======== ========
The $2.6 million of net operating loss carryforwards ("NOL's"), relates to Australian NOL's which do not expire. In addition, $0.6 million of the $1.4 million of tax credit carryforwards do not expire, and $0.2 million expire in 2022. Management expects that the NOL's and tax credit carryforwards will be utilized to offset tax obligations in future periods with the exception of $0.6 million of the tax credit carryforwards that will begin to expire in 2012. Thus, a corresponding $0.6 million valuation allowance is recorded as of September 30, 2006. An analysis of the change in the valuation allowance during the current fiscal year is as follows (in thousands): Valuation Allowance as of September 30, 2005 $ 510 Foreign tax credit carryforwards generated 130 ----- Valuation Allowance as of September 30, 2006 $ 640 ===== Under SFAS 123(R), $1.5 million of United States NOL's relates to windfall tax benefits which will not be realized or recorded until the deduction reduces our United States income taxes payable. At such time, the amount will be recorded as an increase to paid-in-capital. We apply the "with-and-without" approach when utilizing certain tax attributes whereby windfall tax benefits are used last to offset taxable income. We do not record federal income taxes on the undistributed earnings of our foreign subsidiaries that we consider to be permanently reinvested in foreign operations. In addition, there was no cumulative amount of such undistributed earnings and profits at September 30, 2006. 36 The differences between the United States statutory and our effective income tax rate are as follows: Fiscal Fiscal Fiscal 2006 2005 2004 ------ ------ ------ Statutory income tax rate 35% 35% 35% Resolution of prior period tax items (7) (23) (3) Increase (decrease) in tax rate resulting from - Foreign tax rate differentials, net of foreign tax credit utilization (22) (14) 7 --- --- -- Effective income tax rate 6% (2%) 39% === === ==
As a result of working in foreign jurisdictions, we earned a high level of operating income earned in certain nontaxable and deemed profit tax jurisdictions which significantly reduced our effective tax rate for the current fiscal year when compared to the United States statutory rate. In addition, we reversed a $1.8 million tax contingent liability during fiscal year 2006 due to the expiration of the statute of limitations in a foreign jurisdiction. Also, we were advised by a foreign tax authority that it had approved acceptance of certain amended prior year tax returns. The acceptance of these amended tax returns, along with the fiscal year 2005 tax return in this foreign jurisdiction, resulted in the recognition of a $4.6 million tax benefit in the third quarter of the current fiscal year. During the first quarter of fiscal year 2005, we received a $1.7 million tax refund in Malaysia related to a previously reserved tax receivable. A $1.0 million deferred tax benefit was recognized in June 2005 due to the filing and subsequent acceptance by the local tax authority, of amended prior year tax returns. On December 1, 2005, we received notification from the United States Department of Treasury that a previously reserved United States income tax refund we had been pursuing for over two years had been approved for payment. Based upon this approval, we reduced our income tax provision by the refund amount of $3.3 million for the year ended September 30, 2005. Furthermore, during fiscal year 2005, operating income earned in certain nontaxable and deemed profit tax jurisdictions was higher when compared to the prior fiscal year, including business interruption proceeds earned by the ATWOOD BEACON in a zero tax jurisdiction for approximately three and a half months, which contributed to our lower effective tax rate. As a result of these items, our effective tax rate for fiscal year 2005 was significantly less when compared to the prior fiscal year and the United States statutory rate. NOTE 7 - CAPITAL STOCK PREFERRED STOCK- In 1975, 1,000,000 shares of preferred stock with no par value were authorized. In October 2002, we designated Series A Junior Participating Preferred Stock. No preferred shares have been issued. COMMON STOCK- During the current fiscal year, our shareholders approved a proposal to increase the authorized shares of our common stock from 20,000,000 shares to 50,000,000 shares. On March 2, 2006, the Board of Directors declared a two-for-one stock split of our common stock effected in the form of a 100% common stock dividend. All shareholders of record on March 24, 2006 received one additional share of common stock for each share held on that date. The additional shares of common stock were distributed in the form of a stock dividend on April 7, 2006. All share and per share amounts in the accompanying condensed consolidated financial statements and related notes have been adjusted to reflect the stock split for all periods presented. In October 2004, we sold in a public offering 2,350,000 shares of our common stock at an effective net price (before expenses) of $22.92 for net proceeds of approximately $53.6 million. We used these proceeds and cash on hand to repay the $55 million outstanding as of September 30, 2004 under the revolving portion of our Credit Facility. 37 RIGHTS AGREEMENT - In September 2002, we authorized and declared a dividend of one Right (as defined in Rights Agreement effective October 18, 2002, which governs the Rights) for each outstanding share of common stock as of November 5, 2002, subject to lender approval and consent, which was obtained. One Right will also be associated with each share of common stock that becomes outstanding after November 5, 2002 but before the earliest of the Distribution Date, the Redemption Date and the Final Expiration Date (as defined in Rights Agreement). The Rights are not exercisable until a person or group of affiliated or associated persons begin to acquire or acquires beneficial ownership of 15 percent or more of our outstanding common stock. This provision does not apply to shareholders already holding 15 percent or more of our outstanding common stock as of November 5, 2002 until they acquire an additional 5 percent. In connection with the March 2006 stock split, discussed above, and in accordance with the Rights Agreement, we decreased from one one-thousandth to one two-thousandth of a share the number of shares of our Series A Junior Participating Preferred Stock, no par value, purchasable at a price of $150 upon the exercise of each Right, when exercisable. The redemption price of the Rights was also decreased from $0.01 to $0.005 in connection with the stock split. The Rights are subject to further adjustment for certain future events including any future stock splits. The Rights will expire on November 5, 2012. At September 30, 2006, 500,000 preferred shares have been reserved for issuance in the event that Rights are exercised. NOTE 8 - RETIREMENT PLANS We have two contributory retirement plans (the "Plans") under which qualified participants may make contributions, which together with our contributions, can be up to 100% of their compensation, as defined, to a maximum of $40,000. Participants must contribute from 1 to 5 percent of their earnings as a required contribution ("the basic contribution"). We make contributions to the Plans equal to twice the basic contributions. After six consecutive months of service, an employee can elect to become a participant in a Plan. Our contributions vest 100% to each participant after three years of service with us including any period of ineligibility mandated by the Plans. If a participant terminates employment before becoming fully vested, the unvested portion is credited to our account and can be used only to offset our future contribution requirements. During fiscal years 2006 and 2005, no forfeitures were utilized to reduce our cash contribution requirements while in fiscal year 2004, $120,000 of forfeitures were utilized to reduce our cash contribution requirements. In fiscal years 2006, 2005 and 2004, our actual cash contributions totaled approximately $3.1 million, $2.7 million and $2.4 million, respectively. As of September 30, 2006, there were approximately $0.1 million of contribution forfeitures, which can be utilized to reduce our future cash contribution requirements. NOTE 9 - FAIR VALUE OF FINANCIAL INSTRUMENTS The carrying values of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities included in the accompanying Consolidated Balance Sheets approximate fair value due to the short maturity of these instruments. Since the Credit Facility (as described in Note 5) has a market adjustable interest rate, the carrying value approximated fair value as of September 30, 2006 and 2005. NOTE 10 - CONCENTRATION OF MARKET AND CREDIT RISK All of our customers are in the oil and gas offshore exploration and production industry. This industry concentration has the potential to impact our overall exposure to market and credit risks, either positively or negatively, in that our customers could be affected by similar changes in economic, industry or other conditions. However, we believe that the credit risk posed by this industry concentration is offset by the creditworthiness of our customer base. 38 Revenues from significant customers from the prior three fiscal years are as follows (in thousands): Fiscal Fiscal Fiscal 2006 2005 2004 ------ ------ ------ Woodside Energy Ltd. $ 78,442 $ 30,757 $ 5,825 Burullus Gas Company 39,053 22,118 16,734 Sarawak Shell Bhd. 32,841 24,446 - Hoang Long & Hoan Vu Joint Operating Companies 32,114 16,557 - ExxonMobil Exploration and Production Malaysia, Inc. 8,733 25,331 33,256
NOTE 11 - COMMITMENTS AND CONTINGENCIES OPERATING LEASES Future minimum lease payments for operating leases for fiscal years ending September 30 are as follows (in thousands): 2007...................................1,916 2008...................................1,102 2009.....................................978 2010.....................................845 2011 and thereafter....................3,570 Total rent expense under operating leases was approximately $3.5 million, $1.8 million and $0.6 million for fiscal years ended September 30, 2006, 2005, and 2004 respectively. LITIGATION We are party to a number of lawsuits which are ordinary, routine litigation incidental to our business, the outcome of which, individually, or in the aggregate, is not expected to have a material adverse effect on our financial position, results of operations or cash flows. NOTE 12 - RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS In June 2006, the FASB issued FIN 48, "Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement 109." FIN 48 prescribes a comprehensive model for recognizing, measuring, presenting, and disclosing uncertain tax positions within the financial statements. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006. We are currently evaluating the impact of the adoption of FIN 48 on our consolidated financial position. In September 2005, the FASB issued SFAS No. 157, "Fair Value Measurements", or SFAS No. 157, which defines fair value, establishes methods used to measure fair value and expands disclosure requirements about fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal year beginning after November 15, 2007, and interim periods within those fiscal periods. We are currently analyzing the provisions of SFAS No. 157 and determining how it will affect accounting policies and procedures, but we have not yet made a determination of the impact the adoption will have on our consolidated financial position, results of operations and cash flows. 39 In September 2006, the SEC issued Staff Accounting Bulletin No. 108, "Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements", or SAB 108, which provides guidance on the consideration of the effects of prior year misstatements in quantifying current year misstatements for the purpose of a materiality assessment. SAB 108 requires that the materiality of the effect of a misstated amount be evaluated on each financial statement and the related financial statement disclosures, and that materiality evaluation be based on quantitative and qualitative factors. SAB 108 is effective for fiscal years beginning after November 15, 2006. We do not believe this guidance will have a material impact on our financial position, results of operations or cash flows. NOTE 13 - OPERATIONS BY GEOGRAPHIC AREAS We are engaged in offshore contract drilling. Our contract drilling operations consist of contracting owned or managed offshore drilling equipment primarily to major oil and gas exploration companies. Operating income is contract revenues less operating costs, general and administrative expenses and depreciation. In computing operating income (expense) for each geographic area, other income (expense) and domestic and foreign income taxes were not considered. Total assets are those assets that we use in operations in each geographic area. A summary of revenues and operating margin for the fiscal years ended September 30, 2006, 2005 and 2004 and identifiable assets by geographic areas as of September 30, 2006, 2005 and 2004 is as follows (in thousands): Fiscal Fiscal Fiscal 2006 2005 2004 -------- -------- ------- REVENUES: United States $ 20,249 $ 11,869 $ 9,565 Southeast Asia 99,884 100,631 97,654 Mediterranean Sea 68,970 23,829 28,627 Africa 27,676 - - Australia 59,846 39,827 27,608 -------- -------- -------- $276,625 $176,156 $163,454 ======== ======== ======== OPERATING INCOME (EXPENSE): United States $ 6,778 $ (622) $ (2,197) Southeast Asia 68,875 45,432 30,070 Mediterranean Sea 25,592 2,142 385 Africa 4,768 - - Australia 10,393 (380) 4,678 Coporate general and administrative expenses (20,630) (14,245) (11,389) -------- -------- -------- $ 95,776 $ 32,327 $ 21,547 ======== ======== ======== TOTAL ASSETS: United States $ 69,651 $ 32,583 $ 30,370 Southeast Asia 241,655 302,354 258,648 Mediterranean Sea 42,447 36,980 95,253 Africa 117,760 980 - Australia 117,637 115,523 113,331 General corporate and other 4,679 7,274 1,334 -------- -------- -------- $593,829 $495,694 $498,936 ======== ======== ========
40 NOTE 14 - QUARTERLY FINANCIAL DATA (UNAUDITED) Summarized quarterly results for fiscal years 2006 and 2005 are as follows (in thousands, except per share amounts): QUARTERS ENDED (1)(2) ------------------------------------------------------- December 31, March 31, June 30, September 30, ----------- --------- -------- ------------ Fiscal 2006 - ----------- Revenues $ 55,414 $ 67,529 $ 71,865 $ 81,817 Income before income taxes 17,027 18,318 28,606 27,885 Net income 14,523 15,629 32,791 23,179 Earnings per common share - Basic 0.47 0.51 1.06 0.75 Diluted 0.47 0.50 1.04 0.74 Fiscal 2005 - ----------- Revenues $ 45,426 $ 41,017 $ 43,589 $ 46,124 Income before income taxes 8,143 6,100 5,933 5,432 Net income 8,650 4,711 5,989 6,661 Earnings per common share - Basic 0.29 0.15 0.20 0.22 Diluted 0.28 0.15 0.19 0.21
- ----- (1) The sum of the individual quarterly net income per common share amounts may not agree with year-to-date net income per common share as each quarterly computation is based on the weighted average number of common shares outstanding during that period. (2) Quarter ended December 31, 2005 and all fiscal year 2005 quarters have been restated to reflect a two-for-one stock split effected on March 2, 2006. See Note 7 for futher discussion. 41 DIRECTORS OFFICERS DEBORAH A. BECK (2, 3, 4) JOHN R. IRWIN Corporate Executive, Retired President, Chief Executive Officer Milwaukee, Wisconsin JAMES M. HOLLAND ROBERT W. BURGESS (2, 3, 4) Senior Vice President, Chief Financial Executive, Retired Financial Officer and Secretary Orleans, Massachusetts GLEN P. KELLEY GEORGE S. DOTSON (1, 2, 3, 4) Senior Vice President - Marketing Corporate Executive, Retired and Administration Tulsa, Oklahoma HANS HELMERICH (1, 4) President, Chief Executive Officer Helmerich & Payne, Inc. Tulsa, Oklahoma JOHN R. IRWIN (1) President, Chief Executive Officer Atwood Oceanics, Inc. Houston, Texas JAMES M. MONTAGUE (3,4) Corporate Executive, Retired Houston, Texas WILLIAM J. MORRISSEY (2, 4) Bank Executive, Retired Elkhorn, Wisconsin (1) Executive Committee (2) Audit Committee (3) Compensation Committee (4) Nominating & Corporate Governance Committee - ------------------------------------------- 42 ANNUAL MEETING The annual meeting of stockholders will be held at 10:00 A.M., Central Standard Time, on Thursday, February 8, 2007 at our principal office: 15835 Park Ten Place Drive, Houston, Texas, 77084. A formal notice of the meeting together with a proxy statement and form of proxy will be mailed to stockholders on or about January 9, 2007. TRANSFER AGENT AND REGISTRAR Continental Stock Transfer & Trust Company 2 Broadway New York, New York 10004 FORM 10-K A copy of our Form 10-K to which this Annual Report is an exhibit is filed with the Securities and Exchange Commission and is available free on request by writing to: Secretary, Atwood Oceanics, Inc. P. O. Box 218350 Houston, Texas 77218 We file our annual report on Form 10-K, quarterly and current reports, proxy statements, and other information with the SEC. Our annual report on Form 10-K for the year ended September 30, 2006 includes as exhibits all required Sarbanes-Oxley Act Section 302 certifications by our CEO and CFO regarding the quality of our public disclosure. Our SEC filings are available to the public over the internet at the SEC's web site at http://www.sec.gov. Our website address is www.atwd.com. We make available free of charge on or through our website our annual report on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Information on our website is not incorporated by reference into this report or made a part hereof for any purpose. You may also read and copy any document we file, including our Form 10-K, at the SEC's Public Reference Room at 450 Fifth Street, NW, Washington, DC 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference rooms and copy charges. Each year, our CEO must certify to the NYSE that he is not aware of any violations of NYSE corporate governance listing standards by us. Our CEO's certification for fiscal year 2005 was submitted to the NYSE. STOCK PRICE INFORMATION - The common stock of Atwood Oceanics, Inc. is traded on the New York Stock Exchange ("NYSE") under the symbol "ATW". No cash dividends on common stock were paid in fiscal year 2005 or 2006, and none are anticipated in the foreseeable future. We have approximately 3,300 beneficial owners of our common stock based upon information provided to us by a third party shareholder services provider dated November 27, 2006. As of December 11, 2006, the closing sale price of the common stock of Atwood Oceanics, Inc., as reported by NYSE, was $50.76 per share. The following table sets forth the range of high and low sales prices per share of common stock as reported by the NYSE for the periods indicated. Fiscal Fiscal 2006 2005 ------------------ ------------------ Quarters Ended Low High Low High - -------------- ------ ------ ----- ----- December 31 $ 32.55 $ 42.75 $ 22.99 $ 26.99 March 31 39.90 51.66 23.53 35.63 June 30 42.29 58.44 25.07 34.95 September 30 39.86 50.64 29.40 43.06 43 BAR CHART - REVENUES ($ MILLIONS) 2002 2003 2004 2005 2006 ---- ---- ---- ----- ---- $149.2 $144.8 $163.5 $176.2 $276.6 BAR CHART - CAPITAL EXPENDITURES ($ MILLIONS) 2002 2003 2004 2005 2006 ---- ---- ---- ---- ---- $89.4 $101.8 $6.5 $25.6 $78.5 BAR CHART - OPERATING INCOME ($ MILLIONS) 2002 2003 2004 2005 2006 ---- ----- ---- ---- ---- $40.1 $6.5 $21.5 $32.3 $95.8 BAR CHART - NET INCOME (LOSS) ($ MILLIONS) 2002 2003 2004 2005 2006 ---- ---- ---- ---- ---- $28.3 ($12.8) $7.6 $26.0 $86.1
44 EX-21 4 exh211.txt EXHIBIT 21.1 SUBSIDIARY COMPANIES AND STATE OR JURISDICTION OF INCORPORATION UNITED STATES - Atwood Drilling, Inc. Delaware 100% Atwood Hunter Co. Delaware 100% Atwood Management, Inc. Delaware 100% Atwood Oceanics Management, LP Delaware 100% ATW Management, Inc. Delaware 100% Atwood Deep Seas, Ltd. Texas 100% FOREIGN - Atwood Oceanics Drilling Pty. Ltd. Australia 100% Atwood Oceanics Australia Pty Limited Australia 100% Atwood Oceanics Platforms Pty. Ltd. Australia 100% Atwood Oceanics Services Pty. Ltd. Australia 100% Atwood Oceanics West Tuna Pty. Ltd. Australia 100% Atwood Oceanics Australia Superannuation Fund Pty. Ltd. Australia 100% Atwood Oceanics Pacific Limited Cayman Islands, B.W.I. 100% Alpha Offshore Drilling Services Cayman Islands, B.W.I. 100% Atwood Oceanics International Ltd Cayman Islands, B.W.I. 100% Swiftdrill Offshore Drilling Services Cayman Islands, B.W.I. 100% Swiftdrill, Inc. Cayman Islands, B.W.I. 100% Atwood Oceanics Leasing Limited Labuan 100% Atwood Oceanics (M) Sdn Bhd Malaysia 100% Clearways Offshore Drilling Sdn. Bhd. Malaysia 49% Drillquest (M) Sdn. Bhd. Malaysia 100% PT Alpha Offshore Drilling Indonesia 100% PT Pentawood Offshore Drilling Indonesia 80% Aurora Offshore Services Gmbh Germany 100% Swiftdrill Nigeria Limited Nigeria 60% Alpha Offshore Drilling (Cambodia) Ltd. Cambodia 100% Alpha Offshore Drilling (S) Pte. Ltd. Singapore 100% Atwood Oceanics Services Singapore 100% Atwood Oceanics Malta Ltd. Malta 100% Atwood Offshore Drilling Limited Hong Kong 100% Atwood Oceanics (NZ) Limited New Zealand 100%
EX-23 5 exh231.txt EXHIBIT 23.1 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (No. 33-52065; No. 333-74255 and No. 333-87786) and on Form S-3 (No. 333-92388 and 333-117534) of Atwood Oceanics, Inc. of our report dated December 12, 2006 relating to the consolidated financial statements, management's assessment of the effectiveness of internal control over financial reporting and the effectiveness of internal control over financial reporting, which appears in the Annual Report to Shareholders and which is incorporated in this Annual Report on Form 10-K. /S/ PRICEWATERHOUSECOOPERS LLP PricewaterhouseCoopers LLP Houston, Texas December 13, 2006 EX-31 6 exh311.txt EXHIBIT 31.1 CERTIFICATIONS I, John R. Irwin, certify that: 1. I have reviewed this annual report on Form 10-K of Atwood Oceanics, Inc.; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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; (c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: December 13, 2006 /S/ JOHN R. IRWIN John R. Irwin Chief Executive Officer EX-31 7 exh312.txt EXHIBIT 31.2 CERTIFICATIONS I, James M. Holland, certify that: 1. I have reviewed this annual report on Form 10-K of Atwood Oceanics, Inc.; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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; (c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: December 13, 2006 /S/ JAMES M. HOLLAND James M. Holland Chief Financial Officer EX-32 8 exh321.txt EXHIBIT 32.1 CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report of Atwood Oceanics, Inc. (the "Company") on Form 10-K for the period ended September 30, 2006, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, John R. Irwin, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. ss.1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge: (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of, and for the periods presented. Date: December 13, 2006 /S/ JOHN R. IRWIN John R. Irwin President and Chief Executive Officer EX-32 9 exh322.txt EXHIBIT 32.2 CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report of Atwood Oceanics, Inc. (the "Company") on Form 10-K for the period ended September 30, 2006, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, James M. Holland, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. ss.1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge: (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of, and for the periods presented. Date: December 13, 2006 /s/ JAMES M. HOLLAND James M. Holland Senior Vice President and Chief Financial Officer -----END PRIVACY-ENHANCED MESSAGE-----