10-K

UNITED STATES

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, 2007

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 incorporation or organization) (I.R.S. Employer Identification No.)

15835 Park Ten Place Drive Houston, Texas (Address of principal executive offices) 77084 (Zip Code)

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 Preferred Stock Purchase Rights (Title of each Class)   New York Stock Exchange New York Stock Exchange (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 o

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 o 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 o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation in S-K (229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrants 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 o.

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 o Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o 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, 2007 was $1,833,000,000.

The number of shares outstanding of our Common Stock, $1 par value, as of November 27, 2007:31,675,927.

DOCUMENTS INCORPORATED BY REFERENCE

(1) Annual Report to Shareholders for the fiscal year ended September 30, 2007 - Referenced in Parts I, II and IV of this report.
(2) Proxy Statement for Annual Meeting of Shareholders to be held February 14, 2008 - 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 Texas 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 six regions of the world offshore Southeast Asia, offshore Africa, offshore India, offshore Australia, the Black Sea and the U.S. Gulf of Mexico. Approximately 93%, 93%, and 93% of our contract revenues were derived from foreign operations in fiscal years 2007, 2006 and 2005, 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, Malta, Egypt, Indonesia, 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 the Notes to Consolidated Financial Statements contained in our Annual Report to Shareholders for fiscal year 2007, incorporated by reference herein.

The following table presents our wholly-owned and operating rig fleet as of November 27, 2007:

Rig Name	Rig Type	Upgraded	Water Depth 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 TenderAssist	1992/1999/2006	600
ATWOOD BEACON	Jack-up	2003(1)	400
VICKSBURG	Jack-up	1998	300
RICHMOND	Submersible	2000/2002/2007	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 rig, under construction in Brownsville, Texas, with scheduled delivery in October/November 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 87% and 33% of our available rig days contracted for fiscal years 2008 and 2009, respectively. For many years, one of our strategic focuses has been maintaining high equipment utilization. We had a 100% equipment utilization rate in each of fiscal years 2007 and 2006 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 2007, our operating results significantly increased for fiscal year 2007 compared to fiscal year 2006. 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 year 2008 will reflect a significant improvement over fiscal year 2007 operating results, and we expect our 2008 operating results to be the highest in our history.

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OFFSHORE DRILLING EQUIPMENT

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 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.

DRILLING CONTRACTS

We obtain the contracts under which we operate our units 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 units 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 unit, 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. 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 units. Our active rig utilization, which excludes contractual downtime for rigs upgraded, for fiscal years 2007, 2006 and 2005 was 100%, 100% and 98%, respectively.

Of our current drilling contracts, five of our drilling units have contract terms that extend to the end of fiscal year 2008 or beyond. The ATWOOD EAGLE's contract in Australia extends into fiscal year 2010. The ATWOOD FALCON,

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ATWOOD BEACON and VICKSBURG contracts extend into fiscal year 2009. The current SEAHAWK contract extends to the end of fiscal year 2008. The current ATWOOD SOUTHERN CROSS and ATWOOD HUNTER contracts are expected to terminate in February 2008 and July 2008, respectively, with both rigs expected to be recontracted at increased dayrates. Even though the RICHMOND currently has a one well contract commitment, we expect that this rig will remain highly utilized; however, we expect its dayrate to be down from its current one well commitment of $80,000 to the mid to high $60,000.

We currently expect the following zero rate downtime in fiscal year 2008:

RIG	ESTIMATED QUARTER IN WHICH DOWNTIME COULD OCCUR	ESTIMATED DAYS AT ZERO RATE
ATWOOD HUNTER	End of first quarter to beginning of second quarter	15 to 20 Days
ATWOOD EAGLE	First Quarter	15 Days
ATWOOD FALCON	Fourth quarter of fiscal year 2008 or first quarter of fiscal year 2009	5 to 10 Days
ATWOOD SOUTHERN CROSS	Second Quarter	4 to 10 Days
ATWOOD BEACON	Second Quarter	3 Days
RICHMOND	First Quarter	70 Days

                In addition to the above planned downtime, we are always at risk for unplanned downtime. Thus far in the first quarter of fiscal year 2008, the SEAHAWK and the ATWOOD HUNTER have incurred sixteen (16) days and three (3) days, respectively of unplanned downtime. Maintaining high equipment utilization in up, as well as down, cycles is a big 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 todays 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. 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.

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, capsizing, grounding, collision and damage from severe weather conditions.

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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, builders risk, cargo, war risks, protection and indemnity, and excess liability, among others.

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 2007, we performed operations for 15 customers. Because of the relatively limited number of customers for which we can operate at any given time, revenues from 3 different customers amounted to 10% or more of our revenues in fiscal year 2007 as indicated below:

Customer	Percentage of Revenues
Woodside Energy Ltd.	17%
BHP Billiton Petroleum Pty	13%
Sarawak Shell Bhd.	13%

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

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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 India, offshore Australia, the Black Sea, and shallow waters in the U.S. Gulf of Mexico, offer the potential for continuing high utilization. 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, and expect significant growth in demand for oil and gas driven by Chinas and Indias 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 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 Chinaand 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, Malta, Egypt, Indonesia, Singapore and the United Kingdom.

Virtually all of our tax provision for fiscal years 2005, 2006 and 2007 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. Our effective tax rate for fiscal year 2007 was 15%. Excluding any discrete items that may occur, we expect our effective tax rate to be approximately 15% for fiscal year 2008.  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. The cumulative amount of such undistributed earnings was approximately $128 million at September 30, 2007.  It is not practicable to estimate the amount of any deferred tax liability associated with the undistributed earnings. If these earnings were to be remitted to us, any United States income taxes payable would be substantially reduced by foreign tax credits generated by the repatriation of the earnings. Such foreign tax credits totaled approximately $57 million at September 30, 2007.

EMPLOYEES

We currently employ approximately 900 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 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.

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.

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.

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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 oil spills and liability for damages resulting from such spills. Few defenses exist to the liability imposed by OPA, and the liability could be substantial. Failure to comply with ongoing requirements or inadequate cooperation in the event of a spill could subject a responsible party to civil or criminal enforcement action. 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 canceling 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.

SECURITIES LITIGATION SAFE HARBOR STATEMENT

Statements included in this report and the documents incorporated herein by reference 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 managements 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.

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Important factors that could cause our actual results of operations, financial condition or cash flows 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;

• 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;

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• 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 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. See also Risk Factors in Item 1A. 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 Managements Discussion and Analysis in our Annual Report to Shareholders for fiscal year 2007 incorporated by reference in Part I, Part II, Part IV 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 SECs 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. 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 SECs 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.

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

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this report on 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:

• prevailing oil and natural gas prices;

• expectations about future prices;

• the cost of exploring for, producing and delivering oil and natural gas;

• the sale and expiration dates of available offshore leases;

• worldwide demand for petroleum products;

• current availability of oil and natural gas resources;

• the rate of discovery of new oil and natural gas reserves in offshore areas;

• local and international political and economic conditions;

• technological advances;

• ability of oil and natural gas companies to generate or otherwise obtain funds for capital;

• the ability of the Organization of Petroleum Exporting Countries, or OPEC, to set and maintain production levels and pricing;

• political or other disruptions that limit exploration, development and production in oil-producing countries;

• the level of production by non-OPEC countries; and

• 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:

• shortages of equipment, materials or skilled labor;

• unscheduled delays in the delivery of ordered materials and equipment;

• unanticipated cost increases;

11

• weather interferences;

• difficulties in obtaining necessary permits or in meeting permit conditions;

• design and engineering problems; and

• 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:

• catastrophic marine disaster;

• adverse sea and weather conditions;

• mechanical failure;

• navigation errors;

• collision;

• oil and hazardous substance spills, containment and clean up;

• labor shortages and strikes;

• damage to and loss of drilling rigs and production facilities; and

• 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.

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

12

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., BHP Billiton Petroleum Pty and Sarawak Shell Bhd. provided approximately 17%, 13%, and 13%, respectively of our consolidated revenues in fiscal year 2007. 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:

• costly delays or cancellations of drilling operations;

• serious damage to, or destruction of, equipment;

• personal injury or death;

• significant impairment of producing wells or underground geological formations; and

• 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:

• we may experience a higher number of accidents in the future than expected;

• our insurance coverage may prove inadequate to cover losses that are greater than anticipated;

• our insurance deductibles may increase; or

13

• 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:

• legal and governmental regulatory requirements;

• difficulties and costs of staffing and managing international operations;

• language and cultural differences;

• potential vessel seizure or nationalization of assets;

• import-export quotas or other trade barriers;

• renegotiation or nullification of existing contracts;

• difficulties in collecting accounts receivable and longer collection periods;

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• foreign and domestic monetary policies;

• political and economic instability;

• terrorist acts, war and civil disturbances;

• assault on property or personnel;

• travel limitations or operational problems caused by severe acute respiratory syndrome (SARS) or other public health threats;

• imposition of currency exchange controls; and

• 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.

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.

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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 November 28, 2007, 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. OR ANY OTHER LARGE SHAREHOLDER 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. or any other large shareholder are sold, 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.

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:

• 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.

• 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.

• 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.

• 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.

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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 2007, which is incorporated by reference herein.

Collectively since fiscal year 1997, we have expended approximately $400 million (including the current upgrade in progress on the RICHMOND) in upgrading seven offshore mobile drilling units. The timing and costs of the various upgrades are as follows:

DRILLING UNITS	YEAR UPGRADE 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
RICHMOND (IN PROGRESS)	2007	15 (estimated)
		$ 401

The ATWOOD AURORA, another ultra-premium jack-up, will become our ninth drilling unit upon expected completion of its construction on or before October/November 2008. This drilling unit is expected to have a total construction cost of approximately $160 million.

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 2007, 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 November 27, 2007 there were approximately 10,700 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 under the symbol ATW.

We did not pay cash dividends in fiscal years 2006 or 2007 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

17

profile in the industry, we expect to utilize cash reserves at the appropriate time to upgrade existing equipment or to acquire additional equipment. Both our credit facility in place at September 30, 2007 and our new credit facility entered into in October 2007, prohibit payments of cash dividends on common stock without lender approval. In March 2006, we declared a two-for-one stock split of our common stock effected in the form of a 100% common stock dividend.

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 2007, 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 2007, which is incorporated by reference herein.

Stock Performance Graph required by this item may be found under the caption heading Stock Price Information in our Annual Report to Shareholders for fiscal year 2007, 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 2007, 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 under the caption Managements Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report to Shareholders for fiscal year 2007, 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 Managements Discussion and Analysis of Financial Condition and Results of Operations section of the Companys Annual Report to Shareholders for fiscal year 2007, 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 2007, 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 SECs 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) Managements Annual Report on Internal Control over Financial Reporting

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A copy of our Managements Report of Internal Control over Financial Reporting is included in our Annual Report to Shareholders for fiscal year 2007, which is incorporated by reference herein.

(c) Attestation Report of the Independent Registered Public Accounting Firm.

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 2007, 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 14, 2008, 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 14, 2008, 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 14, 2008, 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 14, 2008, 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 14, 2008, 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

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1. and 2. FINANCIAL STATEMENTS AND SCHEDULES

The following financial statements, together with the report of PricewaterhouseCoopers LLP dated November 28, 2007 appearing in our Annual Report to Shareholders for fiscal year 2007, are incorporated by reference herein:

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets as of September 30, 2007 and 2006

Consolidated Statements of Operations for each of the three years in the period ended September 30, 2007

Consolidated Statements of Cash Flows for each of the three years in the period ended September 30, 2007

Consolidated Statements of Changes in Shareholders' Equity for each of the three years in the period ended September 30, 2007

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. 2007 Long-Term Incentive Plan See Exhibit 10.1.11 hereof.

Form of Stock Option Agreement (2007 Long-Term Incentive Plan) See Exhibit 10.1.12 hereof.

Form of Restricted Stock Award Agreement (2007 Long-Term Incentive Plan) See Exhibit 10.1.13 hereof.

Form of Non-Employee Director Restricted Stock Award Agreement (2007 Long-Term Incentive Plan) See Exhibit 10.1.14 hereof.

Non-Employee Directors Elective Deferred Compensation Plan See Exhibit 10.1.10 hereof.

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Atwood Oceanics, Inc. Retention Plan for Certain Salaried Employees dated effective as of January 1, 2007 See Exhibit 10.2.1 hereof.

Atwood Oceanics, Inc. Retention Plan for Certain Salaried Employees dated effective as of January 1, 2008 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

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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: November 29, 2007

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 and Chief Financial Officer                                          President, Chief Executive Officer and

(Principal Financial and Accounting Officer) Director

Date: November 29, 2007 (Principal Executive Officer)

Date: November 29, 2007

/S/ ROBERT W. BURGESS /S/ GEORGE S. DOTSON

ROBERT W. BURGESS GEORGE S. DOTSON

Director Director

Date: November 29, 2007 Date: November 29, 2007

/S/ HANS HELMERICH /S/ WILLIAM J. MORRISSEY

HANS HELMERICH WILLIAM J. MORRISSEY

Director Director

Date: November 29, 2007 Date: November 29, 2007

/S/ DEBORAH A. BECK /S/JAMES R. MONTAGUE  

DEBORAH A. BECK JAMES R. MONTAGUE

Director Director

DATE: November 29, 2007 DATE: November 29, 2007

22

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).

3.3 Amendment No. 1 to Second Amended and Restated By-Laws dated June 7, 2007 (Incorporated herein by reference to Exhibit 3.1 of our Form 8-K filed June 12, 2007).

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).

10.1.10 Non-Employee Directors Elective Deferred Compensation Plan effective December 1, 2007 (Incorporation herein by reference to Exhibit 10.1 on our Form 8-K filed November 14, 2007.

10.1.11 Atwood Oceanics, Inc. 2007 Long-Term Incentive Plan (Incorporated herein by reference to Appendix B to our definitive proxy statement on Form DEF 14A filed January 9, 2007).

10.1.12 Form of Stock Option Agreement 2007 Long-Term Incentive Plan (Incorporated herein by reference to Exhibit 10.1.1 of our Form 10-Q for the quarter ended March 31, 2007).

10.1.13 Form of Restricted Stock Award Agreement 2007 Long-Term Incentive Plan (Incorporated herein by reference to Exhibit 10.1.2 of our Form 10-Q for the quarter ended March 31, 2007).

10.1.14 Form of Non-Employee Director Restricted Stock Award Agreement 2007 Long-Term Incentive Plan (Incorporated herein by reference to Exhibit 10.1.3 of our Form 10-Q for the quarter ended March 31, 2007).

23

10.2.1 Atwood Oceanics, Inc. Retention Plan for Certain Salaried Employees effective as of January 1, 2007 (Incorporated herein by reference to Exhibit 10.2.2 of our Form 10-K for the year ended September 30, 2006).

*10.2.2 Atwood Oceanics, Inc. Retention Plan for Certain Salaried Employees dated as of January 1, 2008.

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 $300 million dated October 26, 2007 among the Company, Atwood Oceanics Pacific Limited and Nordea Bank Finland Plc and other Financial Institutions (Incorporated herein by reference to Exhibit 10.1 of our Form 8-K filed November 1, 2007).

10.5 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

24

EX-10

EXHIBIT 10.2.2

___________________________________

ATWOOD OCEANICS, INC.

RETENTION PLAN

FOR CERTAIN SALARIED EMPLOYEES

___________________________________

Effective as of January 1, 2008

This Plan will terminate automatically

as of December 31, 2008 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 1^st day of January, 2008.

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, 2008, 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, 2008, 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 by

2

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

3

and 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 Employee hereunder.

6

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

EXHIBIT 13.1

2007 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 domestic and international offshore drilling and completion of exploratory and developmental oil and gas wells and related services. Presently, we own and operate a premium, modern fleet of eight mobile offshore drilling units. Since fiscal year 1997, we have 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 in October/November 2008, the ATWOOD AURORA will be our ninth owned 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

	2007	2006
	(In Thousands)
FOR THE YEAR ENDED SEPTEMBER 30:
REVENUES	$ 403,037	$ 276,625
NET INCOME	139,024	86,122
CAPITAL EXPENDITURES	91,306	78,464
AT SEPTEMBER 30:
NET PROPERTY AND EQUIPMENT	$ 493,851	$ 436,166
TOTAL ASSETS	717,724	593,829
TOTAL SHAREHOLDERS' EQUITY	615,855	458,894

1

TO OUR SHAREHOLDERS AND EMPLOYEES:

We are pleased to report that 2007 was another record fiscal year for the Company with notable achievements in many areas. Revenues, operating cash flows and net income for fiscal year 2007 were the highest in our history. Our net income of $139 million, or $4.37 per diluted share, improved on our previous record net income of $86 million, or $2.74 per diluted share, for fiscal year 2006. Based upon our strong current financial position and market outlook, we believe that continuing to pursue our current strategy will further enhance shareholder value in the future.

Our strategy focuses on safe, quality operations; premium equipment; meeting the needs of our clients and being leveraged to attractive international markets. This strategy has served us well by enhancing shareholder value and continuing to guide our path forward. The Company is well-positioned for the future with a distinct strategy and position in the industry, particularly given our size.

Our existing fleet of eight owned operating units is working with key clients in some of the world’s most attractive offshore markets. During the past fiscal year, we achieved fleet utilization of 100%. Our current estimated contract backlog in terms of available rig days for our eight units is approximately 87%  for fiscal year 2008 and 33% for fiscal 2009. This backlog provides a combination of earnings visibility and future earnings upside potential, particularly with our deepwater and international leverage. Our new ultra-premium jack-up, the ATWOOD AURORA, now under construction in Brownsville, Texas, with expected delivery in October/November 2008, will offer growth potential when it commences operation as our ninth offshore drilling unit.

We continue to strengthen our balance sheet and the Company currently has no outstanding term debt. In October 2007, we replaced our then existing credit agreement with a five-year $300 million revolving loan facility. This new facility, which is on more favorable terms than our previous facility, will provide funding for future growth opportunities and for general corporate needs.

With our strong balance sheet and the likelihood of record cash flows and financial results, we expect to be in a position to consider opportunities when the times are right. Based on longer-term expectations for energy demand, the outlook for the markets we serve is positive, particularly our international deep water markets. Accordingly, we are working to identify and pursue value-enhancing growth opportunities as well as evaluating the best use of future cash flow. In considering growth opportunities, we want to remain leveraged to our international deepwater markets, particularly for conventionally moored semisubmersibles in the range of 6,000 to 8,000 feet of water supported by acceptable term contract opportunities. We estimate current project costs (including capitalized interest) of $550,000,000 to $600,000,000 to construct a new semisubmersible with the specifications to meet our clients’ future deepwater needs. Time for rig construction will put new rig delivery approximately four years after commitment.

Our international scope of activities means much to us, as does our involvement in many different communities where we operate or maintain offices. Atwood Oceanics is proud of its long operating history and reputation – and it’s long-standing relationships with clients. We owe much to the talent and contributions of both our U.S. and international employees for our performance during 2007. Each day, our agenda emphasizes safe, high standards of performance, the value of our committed workforce and continued development of our organization for the future. We aspire to continue building our longer-term position as a leader in our industry.

We are grateful for our shareholders trust and the successes delivered by our talented and dedicated multi-national employees during 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  data and ratios)		At  or For the  Years September 30,
		2007			2006			2005			2004			2003
STATEMENTS OF OPERATIONS   DATA:
Revenues	$	403,037		$	276,625		$	176,156		$	163,454		$	144,765
Contract drilling costs		(186,949	)		(144,366	)		(102,849	)		(98,936	)		(98,500	)
Depreciation		(33,366	)		(26,401	)		(26,735	)		(31,582	)		(25,758	)
General and administrative expenses		(23,929	)		(20,630	)		(14,245	)		(11,389	)		(14,015	)
Gain on sale of equipment		414			10,548			--			--			--
OPERATING INCOME		159,207			95,776			32,327			21,547			6,492
Other (expense) income		752			(3,940	)		(6,719	)		(9,145	)		(4,856	)
Tax (provision) benefit		(20,935	)		(5,714	)		403			(4,815	)		(14,438	)
NET INCOME (LOSS)	$	139,024		$	86,122		$	26,011		$	7,587		$	(12,802	)
PER SHARE DATA:
Earnings (loss) per common share:
Basic	$	4.44		$	2.78		$	0.86		$	0.27		$	(0.46	)
Diluted	$	4.37		$	2.74		$	0.83		$	0.27		$	(0.46	)
Average common shares outstanding:
Basic		31,343			30,936			30,412			27,718			27,692
Diluted		31,814			31,442			31,220			28,064			27,692
FLEET DATA:
Number of rigs owned or managed, at end
of period		8			10			11			11			11
Utilization rate for in-service rigs (1)		100	%		100	%		98	%		93	%		92	%
BALANCE SHEET DATA:
Cash and cash equivalents	$	100,361		$	32,276		$	18,982		$	16,416		$	21,551
Working capital		158,549			86,308			35,894			32,913			26,063
Net property and equipment		493,851			436,166			390,778			401,141			443,102
Total assets		717,724			593,829			495,694			498,936			522,674
Total long-term debt (including current  portion)		18,000			64,000			90,000			181,000			205,000
Shareholders' equity (2) (3)		615,855			458,894			362,137			271,589			263,467
Ratio of current assets to current liabilities		3.75			2.41			1.64			1.55			1.52

Notes -
	(1)	Excludes managed rigs, the SEASCOUT (sold in fiscal year 2006), and contractual downtime on rigs upgraded.

(2) We have never paid any cash dividends on our common stock.

(3) In October 2004, we sold 2,350,000 shares of common stock in a public offering.

3

OFFSHORE DRILLING OPERATIONS

RIG NAME

YEAR UPGRADED

MAXIMUM WATER DEPTH

PERCENTAGE OF FY 2007 REVENUES (1)

LOCATION AT NOVEMBER 27 , 200 7

CUSTOMER

CONTRACT STATUS AT NOVEMBER 27 , 2007

SEMISUBMERSIBLES -

ATWOOD EAGLE

2000/2002

5,000 Ft.

14%

Offshore Australia

BHP BILLITON PETROLEUM PTY (“BHPB”)

The rig is currently working under a drilling program for BHPB which is expected to extend to May 2008. 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 (“Woodside”). It should take until June/July 2010 before these drilling commitments are completed.

ATWOOD HUNTER

1997/2001

5,000 Ft.

21%

Offshore Egypt

BURULLUS GAS CO. (“BURULLUS”)

The rig is currently working under a drilling program for Burullus which should take until mid December 2007 to complete. Following the completion of the Burullus contract, the rig will be moved to a shipyard in Malta to undergo an estimated 20 day equipment upgrade and will then move to Mauritania to complete the previously suspended Woodside contract which should extend to July 2008.

ATWOOD FALCON

1998/2006

5,000 Ft.

13%

Offshore Malaysia

SARAWAK SHELL BERHAD (“SHELL”)

The rig is currently working under a long-term drilling commitment with Shell which extends to July 2009.

ATWOOD SOUTHERN CROSS

1997/2006

2,000 Ft.

15%

Offshore Bulgaria and Turkey

MELROSE RESOURCES (“MELROSE”) AND TURKIYE PETROLLERI A.O. (“TPAO”)

The rig is currently working under drilling commitments with Melrose and TPAO which should take until February 2008 to complete. Upon completion of this commitment, the rig has a contract commitment with ENI Spa AGIP Exploration & Production Division to drill two (2) firm wells plus two (2) option wells which should take approximately six months to complete if both option wells are drilled.

CANTILEVER JACK-UPS –

ATWOOD BEACON

Constructed in 2003

400 Ft.

10%

Offshore India

GUJARAT STATE PETROLEUM CORPORATION LTD. (“GSPC”)

The rig is currently working under a drilling commitment for GSPC which extends to January 2009.

VICKSBURG

1998

300 Ft.

10%

Offshore Thailand

CHEVRON OVERSEAS PETROLEUM (“CHEVRON”)

The rig is currently working under a drilling commitment for Chevron which extends to June 2009.

ATWOOD AURORA

Under Construction

350 Ft.

0%

N/A

N/A

The rig is under construction in Brownsville, Texas with expected delivery in October/November 2008.

SUBMERSIBLE –

RICHMOND

2000/2002 /2007

70 Ft.

7%

Shipyard

HELIS OIL & GAS (“HELIS”)

The rig is currently in a shipyard in Mississippi undergoing a life enhancement upgrade, which is expected to be completed in December 2007. The rig has one (1)remaining well to drill for Helis.

SEM ISUBMERSIBLE TENDER ASSIST UNIT -

SEAHAWK

1992/1999 /2006

600 Ft.

8%

Offshore Equatorial Guinea

AMERADA HESS EQUATORIAL GUINEA, INC. (“HESS”)

The rig is currently working under a contractual commitment with Hess which extends to September 2008. Hess also has four (4) six-month options.

(1) Percentages do not add to 100% as the table does not include 2% of fiscal year 2007 revenues earned pursuant to our Australia Management Contracts prior to their termination during fiscal year 2007.

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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;

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§ 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, 2007, 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.

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MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

MARKET OUTLOOK

Revenues, operating cash flows and net income for fiscal year 2007 were the highest in our history. Currently, we have approximately 87% of our available rig days contracted for fiscal year 2008. A comparison of the average per day revenues for fiscal year 2007 and 2006 for each of our eight active drilling units to their highest currently contracted dayrate commitment is as follows:

	Average Per Day Revenues		(1)
	Fiscal Year 2006	Fiscal Year  2007		Current Highest Contracted Dayrate Commitment (1)		Percentage Change from Fiscal Year 2007 to Highest Currently Contracted Dayrate Commitment
ATWOOD EAGLE	$129,000	$160,000		$405,000		153%
ATWOOD HUNTER	172,000	234,000		240,000		3%
ATWOOD FALCON	83,000	138,000		187,000	(2)	36%
ATWOOD SOUTHERN CROSS	82,000	171,000		380,000		122%
ATWOOD BEACON	88,000	109,000		133,500		22%
VICKSBURG	82,000	110,000		154,000		40%
SEAHAWK	32,000	84,000		93,000	(3)	11%
RICHMOND	55,000	81,000		80,000		---
(1)  Average per day revenues include dayrate and service revenues and amortized deferred fees while the highest currently contracted dayrate commitment includes estimated amortized deferred fees where noted.
(2) At a certain water depth, the dayrate would increase to $200,000; however we currently expect most, if not all, work will be at the $160,000 dayrate level which, with estimated amortized deferred fees of $27,000 per day results in the commitment amount of $187,000.
(3) Includes estimated amortized deferred fees of $17,000 per day.

With our backlog of contracted days at increasing rates on a fleetwide basis, we anticipate that revenues, operating cash flows and earnings for fiscal year 2008 will reflect a significant improvement over fiscal year 2007 operating results and thus, would be the highest in our history. In addition, our balance sheet continues to strengthen with no outstanding term debt as of November 27, 2007.

In October 2007, we entered into a new 5-year $300,000,000 non-amortizing revolving credit facility. This new facility will provide funding for future growth opportunities and for general corporate cash needs. We believe we are in a position to be opportunistic when the time is right, and accordingly, we continue to pursue and explore various growth opportunities. In addition to our ultra premium jack-up, ATWOOD AURORA, currently under construction in Brownsville, Texas, with an expected delivery date in October/November 2008 at a total cost (including capitalized interest) of approximately $160 million, we are interested in expanding our semisubmersible fleet if we can identify acceptable term contract opportunities. We estimate total costs (including capitalized interest) to construct a conventionally moored semisubmersible drilling unit with a maximum water depth capability of 6,000 to 8,000 feet would range from $550 million to $600 million and take approximately four years to construct.

Besides focusing on new growth, we also remain focused on increasing the backlog of our existing drilling units at dayrates that provide good returns on our investments. The ATWOOD EAGLE is currently working under a contractual commitment offshore Australia at dayrates ranging from $160,000 to $170,000 which could extend to May 2008. Following completion of this contract commitment, the rig will drill one well at a dayrate of $360,000 (estimated to take 45 days to complete) and then commence a two-year contract commitment (estimated June/July 2008) at a dayrate of $405,000. Immediately following the current contract commitment offshore Egypt that should extend until mid December 2007, the ATWOOD HUNTER will be moved to a shipyard in Malta to undergo an estimated 20 day

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equipment upgrade and will then move to Mauritania to complete the previously suspended Woodside contract at a dayrate of $240,000, which should extend to July 2008; however, the contract term can be extended up to one additional year subject to agreement on dayrate. The ATWOOD FALCON has a contractual commitment, which extends to July 2009, offshore Malaysia at a current dayrate of $160,000 (over a certain water depth the dayrate will be $200,000; however, we believe that most, if not all, wells drilled will be at the $160,000 dayrate level). The ATWOOD SOUTHERN CROSS is currently working in the Black Sea under contract commitments which should extend to December 2007 or January 2008 at dayrate levels ranging from $145,000 to $380,000. Following completion of the Black Sea commitments, the rig will drill one well at a dayrate of $320,000 in the Mediterranean Sea. Upon completion of the Mediterranean Sea well, the rig has a commitment to work offshore Italy for two firm wells plus two option wells at a dayrate of $406,000 which should take approximately six months to complete if both option wells are drilled. The ATWOOD BEACON is currently working offshore India under contract commitments that extend to January 2009 at dayrates ranging from $113,000 to $133,500. The VICKSBURG has a contract commitment offshore Thailand at a dayrate of $154,000 that extends to June 2009. The SEAHAWK is working offshore West Africa under a drilling contract that extends to September 2008; however, this contract provides for four six-month options at the current contracted dayrate plus certain cost escalations. The rig’s current dayrate is approximately $76,000, which with amortized deferred fees of $17,000 per day results in the total daily revenues of $93,000. Our only rig in the U.S. Gulf of Mexico, the RICHMOND, is currently in a shipyard undergoing an approximate $14 million life enhancing upgrade, which is expected to be completed in mid December 2007. Following the shipyard work, the RICHMOND has one well to drill at a dayrate of $80,000. The RICHMOND has been 100% utilized in the Gulf of Mexico for many years and we expect high utilization of this rig during fiscal year 2008; however, we currently expect the rig’s dayrate to decline from $80,000 to the mid to high $60,000’s.

The continuing strong market environment is not only supporting high equipment utilization with historically high dayrates, but also continues to reflect increasing operating costs. Total drilling costs for fiscal year 2007 ($187 million) compared to fiscal year 2006 ($144 million) increased 29%; however, a significant portion of this increase is attributable to higher than anticipated operating costs for the SEAHAWK while working in West Africa during the current fiscal year compared to the prior fiscal year when the SEAHAWK incurred lower operating costs as the rig was idle approximately five months while undergoing an upgrade and relocating to West Africa. Despite our operating results for fiscal year 2007 being the highest in our history, operating costs on the SEAHAWK during the current fiscal year exceeded revenues on that rig by approximately $4 million. We expect to incur operating costs for this rig in excess of revenue in the range of $1 to $2 million in fiscal year 2008. We currently expect a 10% to 12% fleetwide increase in total drilling costs for fiscal year 2008 compared to fiscal year 2007.

In addition to the estimated 70 days and 20 days of zero rate time to be incurred by the RICHMOND and the ATWOOD HUNTER, respectively, during the first quarter of fiscal year 2008 while undergoing their upgrades, we expect the following drilling units to incur planned zero rate time during fiscal year 2008:

ATWOOD EAGLE	15 days of zero rate time during the first quarter for required regulatory inspections and maintenance
ATWOOD FALCON	5 to 10 zero rate days during the fourth quarter for required regulatory inspections and maintenance; however, this zero rate period could be incurred during the first quarter of fiscal year 2009
ATWOOD SOUTHERN CROSS	4 to 10 zero rate days during the second quarter for some maintenance work
ATWOOD BEACON	3 zero rate days during the second quarter for required inspections

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In addition to the above planned zero rate days that could be incurred during fiscal year 2008, unplanned zero rate days can occur at any time. In recent fiscal years, we have incurred approximately 1% to 2% of unplanned zero rate days per year, however, we have already incurred 16 zero rate days and 3 zero rate days on the SEAHAWK and ATWOOD HUNTER, respectively, due to unplanned equipment downtime during the first quarter of fiscal year 2008 through November 27, 2007.

Despite increasing drilling costs, planned zero rate time and the continuing risk of unplanned zero rate time, we expect operating results for fiscal year 2008 will reflect significant improvement over fiscal year 2007 results and assuming no new growth, we could end fiscal year 2008 with increased cash and no outstanding term debt. With our strong balance sheet and continuing trend for improvement in cash flows and financial results at historic levels, we remain focused on identifying value enhancing growth opportunities, as well as evaluating the best use of future cash flows. We remain optimistic that we will identify one or more growth opportunities during fiscal year 2008, with required funding to be supported by our new $300 million credit facility and internally generated funds.

RESULTS OF OPERATIONS

Fiscal Year 2007 Versus Fiscal Year 2006

Revenues for fiscal year 2007 increased 46% compared to the prior fiscal year. A comparative analysis of revenues by rig for fiscal years 2007 and 2006 is as follows:

	REVENUES (In millions)
	Fiscal	Fiscal
	Year 2007	Year 2006	Variance
ATWOOD SOUTHERN CROSS	$ 62.3	$ 29.9	$ 32.4
ATWOOD HUNTER	85.4	62.8	22.6
ATWOOD FALCON	50.5	30.1	20.4
SEAHAWK	30.6	11.6	19.0
ATWOOD EAGLE	58.4	47.0	11.4
VICKSBURG	40.0	30.0	10.0
RICHMOND	29.5	20.2	9.3
ATWOOD BEACON	39.8	32.1	7.7
AUSTRALIA MANAGEMENT CONTRACTS	6.5	12.9	(6.4)
	$ 403.0	$ 276.6	$ 126.4

         The increase in fleetwide revenues during fiscal year 2007 when compared to fiscal year 2006 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. Increases in revenues for the ATWOOD SOUTHERN CROSS, ATWOOD HUNTER, ATWOOD FALCON, SEAHAWK, ATWOOD EAGLE, VICKSBURG, RICHMOND, and the ATWOOD BEACON were related to each of these drilling units working under higher dayrate contracts during the current fiscal year compared to the prior fiscal year. In addition, for approximately five months of fiscal year 2006, the SEAHAWK earned virtually no revenue as the rig was in a shipyard undergoing a life-enhancing upgrade and then relocated to West Africa. Revenue for the AUSTRALIA MANAGEMENT CONTRACTS was lower for the current fiscal year when compared to the prior fiscal year due to decreased activity as the most recent drilling program was completed at the end of the first quarter of fiscal year 2007 with the management contracts terminating during the third quarter of fiscal year 2007.

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Contract drilling costs for fiscal year 2007 increased 29% compared to the prior fiscal year. A comparative analysis of contract drilling costs by rig for fiscal years 2007 and 2006 is as follows:

	CONTRACT DRILLING COSTS (In Millions)
	Fiscal	Fiscal
	Year 2007	Year 2006	Variance
SEAHAWK	$ 28.2	$ 8.4	$ 19.8
ATWOOD EAGLE	35.0	26.8	8.2
ATWOOD FALCON	23.6	16.5	7.1
ATWOOD HUNTER	25.2	18.8	6.4
ATWOOD BEACON	15.5	10.4	5.1
RICHMOND	13.1	10.4	2.7
VICKSBURG	14.0	11.9	2.1
ATWOOD SOUTHERN CROSS	20.7	24.2	(3.5)
AUSTRALIA MANAGEMENT CONTRACTS	5.1	10.8	(5.7)
OTHER	6.5	6.2	0.3
	$ 186.9	$ 144.4	$ 42.5

On a fleetwide basis, wage increases and extra personnel for training and development have resulted in higher personnel costs during fiscal year 2007 for virtually every rig when compared to the prior fiscal year. With the SEAHAWK and ATWOOD HUNTER currently working offshore West and North Africa, respectively, both rigs have experienced increased travel, freight and shorebase costs due to higher transportation and living expenses in West and North Africa. Contract drilling costs for the SEAHAWK also reflect amortization of approximately $5.1 million of deferred expenses during fiscal year 2007 compared to $0.9 million during fiscal year 2006. In addition, as previously noted, the SEAHAWK incurred significantly less operating costs for approximately five months of the prior fiscal year as the rig was in a shipyard undergoing a life enhancing upgrade and then relocated to West Africa. The ATWOOD HUNTER incurred additional maintenance costs during a planned regulatory inspection period in December 2006. In addition to the rising personnel costs mentioned above, the ATWOOD EAGLE and RICHMOND incurred higher maintenance costs during fiscal year 2007 due to the amount and timing of certain maintenance projects when compared to the prior fiscal year. The increase in drilling costs for the ATWOOD FALCON is primarily attributable to planned maintenance during its water depth upgrade which was completed during the first quarter of the current fiscal year. The ATWOOD BEACON has experienced higher maintenance costs in the current fiscal year as it was in a Singapore shipyard having its last leg sections reattached during the first quarter of fiscal year 2007. Drilling costs for the VICKSBURG have remained relatively consistent other than higher personnel costs. Current fiscal year contract drilling costs for the ATWOOD SOUTHERN CROSS have decreased primarily due to $8.6 million of mobilization expense amortization during the prior fiscal year compared to none during the current fiscal year. AUSTRALIA MANAGEMENT CONTRACTS costs have decreased due to the decreased activity resulting from the completion of the current drilling program at the end of the first quarter of the current fiscal year and termination of the contracts during the third quarter of fiscal year 2007. Other drilling costs were relatively consistent with the prior fiscal year.

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Depreciation expense for fiscal year 2007 increased 27% as compared to the prior fiscal year. A comparative analysis of depreciation expense by rig for fiscal years 2007 and 2006 is as follows:

	DEPRECIATION EXPENSE (In millions)
	Fiscal	Fiscal
	Year 2007	Year 2006	Variance
SEAHAWK	$ 6.1	$ 1.6	$ 4.5
ATWOOD FALCON	4.4	2.8	1.6
ATWOOD SOUTHERN CROSS	3.4	2.9	0.5
ATWOOD HUNTER	5.7	5.4	0.3
VICKSBURG	2.9	2.8	0.1
RICHMOND	1.0	0.9	0.1
ATWOOD EAGLE	4.5	4.6	(0.1)
ATWOOD BEACON	5.1	5.3	(0.2)
OTHER	0.3	0.1	0.2
	$ 33.4	$ 26.4	$ 7.0

Depreciation expense increased for the SEAHAWK, ATWOOD FALCON and ATWOOD SOUTHERN CROSS as these rigs have recently undergone upgrades during the current and prior fiscal years, while depreciation expense for all other rigs has remained relatively consistent with the prior fiscal year. The SEAHAWK was almost fully depreciated prior to its upgrade; accordingly, ongoing depreciation expense will approximate fiscal year 2007 levels.

General and administrative expenses for the current fiscal year increased compared to the prior fiscal year primarily due to rising personnel costs and additions to the corporate staff. The fiscal year 2007 increase also includes an approximate $0.7 million increase in annual bonus compensation over the prior fiscal year. The decrease in the gain on sale of equipment reflects the sale of 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 a gain of approximately $10.1 million in the prior fiscal year compared to a gain on sale of equipment of $0.4 million during the current fiscal year. Interest expense has decreased during the current year primarily due to the reduction of our outstanding debt and due to $2.6 million of capitalized interest charges related to the construction of the ATWOOD AURORA during fiscal year 2007 compared to only $1.1 million during fiscal year 2006. Interest income has increased when compared to the prior fiscal year due to interest earned on higher cash balances.

Virtually all of our tax provision for fiscal year 2007 relates to taxes in foreign jurisdictions. Accordingly, due to the high level of operating income earned in certain nontaxable and deemed profit tax jurisdictions during both the current and prior fiscal years, our effective tax rate for these periods was significantly less than the United States federal statutory rate. In addition, during the prior fiscal year, we reversed a $1.8 million tax contingent liability due to the expiration of the statute of limitations in a foreign jurisdiction and recognized a $4.6 million tax benefit due to the acceptance of certain amended prior year tax returns by a foreign tax authority, both of which contributed to the low effective tax rates in the prior fiscal year.

During July 2007, we were notified by the Malaysian tax authorities regarding a potential proposed adjustment relating to fiscal years 2000 to 2003. Although we believe we are in compliance with applicable rules and regulations, we are currently evaluating the merit of the assertions by the Malaysian tax authorities and currently plan to vigorously contest these assertions. While we cannot predict or provide assurance as to the final outcome of these allegations, we do not expect them to have a material adverse effect on our consolidated financial position, results of operations or cash flows.

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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
	Year 2006	Year 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

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. 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.

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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
	Year 2006	Year 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 the following 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. Unless otherwise noted below, the increase in drilling costs for each rig is primarily due to the areas mentioned above.

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 fiscal year 2005 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 fiscal year 2006, and thus, service activities for our AUSTRALIA MANAGEMENT CONTRACTS 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 fiscal year 2005. 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.

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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
	Year 2006	Year 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 fiscal year 2006. During the first quarter of the fiscal year 2006, 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 increased 45% compared to fiscal year 2005 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 fiscal year 2005 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 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%.

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LIQUIDITY AND CAPITAL RESOURCES

As of September 30, 2007, we had $18 million outstanding under the term portion of our senior secured credit facility and no funds borrowed under the $100 million revolving portion of our senior secured credit facility. We were in compliance with all financial covenants at September 30, 2007 and at all times during fiscal years 2007, 2006 and 2005. At September 30, 2007, the collateral for our credit facility consisted primarily of preferred mortgages on all eight of our active drilling units (with an aggregate net book value at September 30, 2007 totaling approximately $378 million). Under the facility, we were not required to maintain compensating balances; however, we were 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.

Subsequent to September 30, 2007, we entered into a new credit agreement with several banks with Nordea Bank Finland PLC, New York Branch, as Administrative Agent for the lenders, as well as Lead Arranger and Book Runner and terminated our prior senior secured credit facility. The new credit agreement provides for a secured 5-year $300,000,000 non-amortizing revolving loan facility with maturity in October 2012, subject to acceleration upon certain specified events of defaults, including breaches of representations or covenants. Loans under the new facility will bear interest at varying rates ranging from 0.70% to 1.25% over the Eurodollar Rate, depending upon the ratio of outstanding debt to earnings before interest, taxes and depreciation. The collateral for the new credit agreement consists primarily of preferred mortgages on three of our active drilling units (ATWOOD EAGLE, ATWOOD HUNTER and ATWOOD BEACON). The new credit agreement contains various financial covenants that, among other things, require the maintenance of certain leverage and interest expense coverage ratios. This new credit facility will provide funding for future growth opportunities and for general corporate needs. As of November 27, 2007, no funds have been borrowed under the new credit facility. In conjunction with the establishment of the new credit agreement, we terminated our prior senior secured credit facility, and we repaid the $18 million then outstanding on our prior senior secured credit facility at the time of termination. We will write off the remaining unamortized loan costs of approximately $0.4 million related to the prior senior secured credit facility in the first quarter of fiscal year 2008.

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 2006, net cash provided by operating activities ranged from a low of approximately $13.7 million in fiscal year 2003 to a high of approximately $85.5 million in fiscal year 2006. For fiscal year 2007, net cash provided by operating activities totaled approximately $190.8 million. Our operating cash flows are primarily driven by our operating income, which reflects dayrates and rig utilization. During fiscal year 2007, we used internally generated cash to expend approximately $63 million toward the construction of the ATWOOD AURORA, approximately $9 million on completing the water depth upgrade and equipment maintenance of the ATWOOD FALCON and approximately $19 million in other capital expenditures. In fiscal year 2008, we currently expect to expend approximately $70 million in completing the construction of the ATWOOD AURORA, approximately $14 million for the life enhancing upgrade for the RICHMOND and approximately $20 million for other capital expenditures.

With approximately 87% of our available operating rig days committed for fiscal year 2008 and approximately 33% committed for fiscal year 2009 at historically high dayrates, we anticipate significant increases in cash flows and earnings during fiscal years 2008 and 2009 when compared to fiscal year 2007. As we repaid the $18 million remaining term portion of our prior senior secured credit facility during October 2007 and have not borrowed against our new senior secured credit facility to date, the only additional firm cash commitment for fiscal year 2008, outside of funding current rig operations, is our expected capital expenditures of approximately $104 million as noted above. We expect to generate more than sufficient cash flows from operations to satisfy these obligations.

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. As of September 30, 2007, we have an unbilled receivable balance of $13.1 million with one customer. This balance relates to contract drilling services performed in August and September 2007, for which billing was postponed awaiting receipt of tax-exempt status from a foreign government. Such amounts were billed subsequent to the current fiscal year end and are expected to be collected in the first quarter of fiscal year 2008. The insurance receivable of $0.6 million at September 30, 2006 related to repairs made to the ATWOOD BEACON during the first quarter of fiscal year 2007.

17

Accrued liabilities have increased by $14.7 million from September 30, 2006 primarily due to the increase of accrued, but unpaid, agent fees and current income tax liabilities.

COMMITMENTS

The following table summarizes our obligations and commitments (in thousands) at September 30, 2007:

	Fiscal		Fiscal		Fiscal		Fiscal		2012 and
	2008		2009		2010		2011		thereaft er
Long-Term Debt (1)	$	18,000	$	-	$	-	$            -	$	-
Purchase Commitments (2)		83,000		-		-	-		-
Operating Leases		1,644		1,029		854	842		2,730
	$	102,644	$	1,029	$	854	$       842	$	2,730

(1) Remaining balance repaid during October 2007.

(2) Rig construction and upgrade commitments for the ATWOOD AURORA and the RICHMOND, respectively.

CRITICAL ACCOUNTING POLICIES

Significant accounting policies are included in Note 2 to our consolidated financial statements for the year ended September 30, 2007. 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 contract drilling revenue in accordance with the terms of the underlying drilling 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.

18

We currently operate eight active offshore drilling units. These assets are premium equipment and should provide many years of quality service. At September 30, 2007, the carrying value of our property and equipment totaled $493.9 million, which represents 69% 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, 2007, we have a $14.3 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.

19

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

In June 2006, the Financial Accounting Standards Board 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.  While we are still finalizing our evaluation of the impact of the adoption of FIN 48, we believe the adoption will result in a decrease to shareholders equity of approximately $4 to $5 million at October 1, 2007.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities”, which provides companies with an option to report selected financial assets and liabilities at fair value and establishes presentation and disclosure requirements to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. GAAP has required different measurement attributes for different assets and liabilities that can create artificial volatility in earnings. The objective of SFAS No. 159 is to help mitigate this type of volatility in the earnings by enabling companies to report related assets and liabilities at fair value, which would likely reduce the need for companies to comply with complex hedge accounting provisions. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We are currently analyzing the provisions of SFAS No. 159 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 2005, the FASB issued SFAS No. 157, “Fair Value Measurements”, 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 years 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.

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 $18 million of long-term debt outstanding under our prior credit facility at September 30, 2007, was floating rate debt. Any debt we incur under our new credit facility will also be floating rate debt. As a result, our annual interest costs in fiscal year 2008 will fluctuate based on interest rate changes. Because the interest rate on our long-term debt is a floating rate and due to the fact that our debt maturing under our prior credit facility would have matured in 2008, the fair value of our long-term debt approximated carrying value as of September 30, 2007. The impact on annual cash flow of a 10% change in the floating rate (approximately 70 basis points) would be immaterial. We did not have any open derivative contracts relating to our floating rate debt at September 30, 2007.

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, 2007 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 $0.3 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, 2007.

20

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, 2007. 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, 2007. 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, 2007, 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, Chief

and Chief Executive Officer Financial Officer and Secretary

November 29, 2007

21

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Atwood Oceanics, Inc.

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 Atwood Oceanics, Inc. and its subsidiaries at September 30, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2007 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2007, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting, which appears on the preceding page. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 3 to the consolidated financial statements, in 2006 the company charged its method of accounting for share-based compensation as a result of adopting the provisions of the Statement of Financial Standards No. 123(R), "Share-Based Payment."

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

Houston, Texas

November 28, 2007

22

Atwood Oceanics, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS

	September 30,
(In thousands)		2007		2006
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	100,361	$	32,276
Accounts receivable, net of an allowance
of $164 and $750 at September 30, 2007
and 2006, respectively		76,597		80,222
Income tax receivable		1,870		65
Insurance receivable		--		550
Inventories of materials and supplies		26,721		22,124
Deferred tax assets		390		2,563
Prepaid expenses and deferred costs		10,240		9,873
Total Current Assets		216,179		147,673
NET PROPERTY AND EQUIPMENT		493,851		436,166
DEFERRED COSTS AND OTHER ASSETS		7,694		9,990
	$	7 17,724	$	593,829
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Current maturities of notes payable	$	18,000	$	36,000
Accounts payable		11,769		11,760
Accrued liabilities		27,861		13,201
Deferred credits		--		404
Total Current Liabilities		57,630		61,365
LONG-TERM DEBT,
net of current maturities:		--		28,000
		--		28,000
LONG TERM LIABILITIES:
Deferred income taxes		14,729		18,591
Deferred credits		24,093		23,284
Other		5,417		3,695
		44,239		45,570
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 31,675 and 31,046 issued
and outstanding at September 30, 2007
and 2006, respectively		31,675		31,046
Paid-in capital		133,224		115,916
Retained earnings		450,956		311,932
Total Shareholders' Equity		615,855		458,894
	$	717,724	$	593,829

The accompanying notes are an integral part of these consolidated financial statements.

23

Atwood Oceanics, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF OPERATIONS

	For Years Ended September 30,
(In thousands, except per share amounts)	2007	2006	2005
REVENUES:
Contract drilling	$ 400,479	$ 276,625	$ 168,500
Business interruption proceeds	2,558	-	7,656
	403,037	276,625	176,156
COSTS AND EXPENSES:
Contract drilling	186,949	144,366	102,849
Depreciation	33,366	26,401	26,735
General and administrative	23,929	20,630	14,245
Gain on sale of equipment	(414)	(10,548)	-
	243,830	180,849	143,829
OPERATING INCOME	159,207	95,776	32,327
OTHER INCOME (EXPENSE):
Interest expense, net of capitalized interest	(1,689)	(5,166)	(7,352)
Interest income	2,441	1,226	633
	752	(3,940)	(6,719)
INCOME BEFORE INCOME TAXES	159,959	91,836	25,608
PROVISION (BENEFIT) FOR INCOME TAXES	20,935	5,714	(403)
NET INCOME	$ 139,024	$ 86,122	$ 26,011
EARNINGS PER COMMON SHARE:
Basic	$ 4.44	$ 2.78	$ 0.86
Diluted	4.37	2.74	0.83
AVERAGE COMMON SHARES OUTSTANDING:
Basic	31,343	30,936	30,412
Diluted	31,814	31,442	31,220

The accompanying notes are an integral part of these consolidated financial statements.

24

Atwood Oceanics, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS

	For Years Ended September 30,
(In thousands)		2007			2006			2005
CASH FLOW FROM OPERATING ACTIVITIES:
Net income	$	139,024		$	86,122		$	26,011
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation		33,366			26,401			26,735
Amortization of debt issuance costs		804			804			804
Amortization of deferred items		(25,729	)		(1,254	)		292
Provision for doubtful accounts		127			726			189
Provision for inventory obsolescence		240			--			--
Deferred federal income tax benefit		(2,169	)		(1,032	)		(1,580	)
Stock-based compensation expense		5,005			4,568			--
Gain on sale of assets		(414	)		(10,548	)		--
Changes in assets and liabilities:
(Increase) decrease in accounts receivable		3,498			(41,083	)		(7,579	)
Decrease in insurance receivable		--			--			9,133
(Increase) decrease in income tax receivable		(1,805	)		3,213			(3,278	)
Increase in inventory		(4,837	)		(6,484	)		(2,839	)
(Increase) decrease in prepaid expenses		(1,454	)		(5,061	)		1,585
Increase in deferred costs and other assets		(4,506	)		(11,419	)		(10,422	)
Increase (decrease) in accounts payable		9			5,287			(2,925	)
Increase (decrease) in accrued liabilities		14,660			3,985			(2,734	)
Increase in deferred credits and other liabilities		34,941			31,226			5,429
Tax benefit from the exercise of stock options		--			--			2,250
Other		--			1			21
		51,736			(670	)		15,081
Net Cash Provided by Operating Activities		190,760			85,452			41,092
CASH FLOW FROM INVESTING ACTIVITIES:
Capital expenditures		(91,306	)		(78,464	)		(25,563	)
Collection of insurance receivable		550			--			15,750
Proceeds from sale of assets		669			26,239			--
Net Cash Used by Investing Activities		(90,087	)		(52,225	)		(9,813	)
CASH FLOW FROM FINANCING ACTIVITIES:
Proceeds from debt		--			20,000			10,000
Principal payments on debt		(46,000	)		(46,000	)		(101,000	)
Proceeds from common stock offering		--			--			53,607
Tax benefit from the exercise of stock options		3,432			--			--
Proceeds from exercise of stock options		9,980			6,067			8,680
Net Cash Provided Used by Financing Activities		(32,588	)		(19,933	)		(28,713	)
NET INCREASE IN CASH AND CASH EQUIVALENTS	$	68,085		$	13,294		$	2,566
CASH AND CASH EQUIVALENTS, at beginning of period	$	32,276		$	18,982		$	16,416
CASH AND CASH EQUIVALENTS, at end of period	$	100,361		$	32,276		$	18,982
Supplemental disclosure of cash flow information:
Cash paid during the year for domestic and foreign income taxes	$	13,095		$	2,654		$	5,977
Cash paid during the year for interest, net of amounts capitalized	$	1,822		$	5,033		$	7,705

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, 2004	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	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
Net income	-	-	-	139,024	139,024
Restricted stock awards	7	7	(7)	-	-
Exercise of employee stock options	622	622	9,358	-	9,980
Stock option and restricted stock
award compensation expense			5,005		5,005
Tax benefit from exercise of employee stock options	-	-	2,952	-	2,952
September 30, 2007	31,675	$ 31,675	$ 133,224	$ 450,956	$ 615,855

The accompanying notes are an integral part of these consolidated financial statements.

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. Upon its expected delivery in October/November 2008, the ATWOOD AURORA will be our ninth owned active mobile offshore drilling unit. Currently, we are involved in active operations in the territorial waters of Australia, Malaysia, Thailand, India, Bulgaria, Egypt, 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. While we did not record a foreign exchange gain or loss during fiscal year 2007, we did record a foreign exchange loss of $0.1 million during fiscal year 2006 and a foreign exchange gain of $0.1 million during fiscal year 2005.

Accounts Receivable

We record trade accounts receivable at the amount we invoice our customers. Our portfolio of accounts receivable is comprised of major international corporate entities and government organizations with stable payment experience. Included within our accounts receivable at September 30, 2007 is an unbilled receivable balance totaling $13.1 million that represents amounts for which contract drilling services have been performed, revenue has been earned based on contractual dayrate provisions and for which collection is deemed probable. Such unbilled amounts were billed subsequent to the current fiscal year end. 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 $0.2 million and $0.8 million, as of September 30, 2007 and 2006, respectively.

Insurance receivable

We had an insurance receivable of $0.6 million as of September 30, 2006, 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 collected the remaining receivable during fiscal year 2007. See Note 4 for further discussion regarding the ATWOOD BEACON incident.

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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 $1.2 million and $1.3 million at September 30, 2007 and 2006, respectively.

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 years 2007 and 2006 was $2.6 million and $1.6 million, respectively. We had no capitalized interest during fiscal year 2005.

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 Drill pipe Furniture and other	5-25 3 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, 2007 and 2006, deferred drydocking costs totaling $1.9 million and $0.6 million, respectively, were included in Deferred Costs and Other Assets in the accompanying Consolidated Balance Sheets.

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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.

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, 2007 and 2006, deferred fees associated with mobilization as well as equipment purchases and upgrades totaled $24.1 million and $23.7 million, respectively. At September 30, 2007 and 2006, deferred costs associated with mobilization and equipment purchases and deferred mobilization costs totaled $4.8 million and $9.0 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.

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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 2007:
	Basic earnings per share	$ 139,024	31,343	$ 4.44
	Effect of dilutive securities –
	Stock options	-	471	(0.07)
	Diluted earnings per share	$ 139,024	31,814	$ 4.37
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

The calculation of diluted earnings per share for the years ended September 30, 2006 excludes consideration of shares of common shares which may be issued in connection with outstanding stock options of 125,200 because such options were antidilutive. These options could potentially dilute basic EPS in the future. For the years ended September 30, 2007 and 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.

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On December 7, 2006, our Board of Directors adopted, and our shareholders subsequently approved on February 8, 2007, the Atwood Oceanics, Inc. 2007 Long-Term Incentive Plan, which is referred to herein as the "2007 Plan." The effective date of the 2007 Plan was December 7, 2006, and awards may be made under the 2007 Plan through December 6, 2017. Under our 2007 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 2007 Plan. We also have two other stock incentive plans, the 2001 Plan and the 1996 Plan, under which there are outstanding stock options and restricted stock awards. However, no additional options or restricted stock will be awarded under the 2001 or 1996 plans.

A summary of share and stock option data for our three stock incentive plans as of September 30, 2007 is as follows:

	2007	2001	1996
	Plan	Plan	Plan
Shares available for future awards or grants	1,997,636	-	-
Outstanding stock option grants	-	737,638	143,750
Outstanding unvested restricted stock awards	2,364	158,050	-

Awards of restricted stock and stock options have both been granted under our stock incentive plans as of September 30, 2007. 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.

The recognition of share-based compensation expense had the following effect on our consolidated statements of operations (in thousands, except per share amounts):

	Year Ended September 30,
	2007	2006
Increase in contract drilling expenses	$ 1,277	$    840
Increase in general and administrative expenses	3,728	3,728
Decrease in income tax provision	(1,305)	(1,305)
Decrease in net income	3,700	3,263
Decrease in earnings per share:
Basic	$ 0.12	$ 0.11
Diluted	$ 0.12	$ 0.10

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We recognize compensation expense on grants of share-based compensation awards on a straight-line basis over the required service period for each award. Unrecognized compensation cost, net of estimated forfeitures, related to stock options and restricted stock awards and the relating remaining weighted average service period is as follows:

	September 30,
	2007	2006
Unrecognized Compensation Cost
Stock options	$ 3,674	$ 4,546
Restricted stock awards	3,902	2,710
Total	$ 7,576	$ 7,256
Remaining weighted average service period (Years)	2.1	2.4

Stock Options

Under our stock incentive plans, the exercise price of each stock option must be equal to or greater than 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 2007 and 2001 Plans 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.

The total fair value of stock options vested during years ended September 30, 2007, 2006 and 2005 was $2.1 million, $3.2 million and $2.9 million, respectively. The per share weighted average fair value of stock options granted during years ended September 30, 2007, 2006 and 2005 was $23.64, $17.87 and $10.22, 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
	2007	2006	2005
Risk-Free Interest Rate	4.53%	4.50%	4.27%
Expected Volatility	45.96%	41.62%	35.00%
Expected Life (Years)	5.25	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 10 to 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.

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A summary of stock option activity for years ended September 30, 2005, 2006 and 2007 is as follows:

			Wtd. Avg.
		Wtd. Avg.	Remaining	Aggregate
	Number of	Exercise	Contractual	Intrinsic
	Options	Price	Life (Years)	Value (000s)
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
Outstanding at October 1, 2006	1,436,950	$ 19.56
Granted	79,400	49.97
Exercised	(621,874)	16.05		$ 27,680
Forfeited	(13,088)	32.95
Outstanding at September 30, 2007	881,388	$ 24.54	6.5	$ 45,854
Exercisable at September 30, 2007	480,245	$ 19.62	5.5	$ 27,345

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. Awards of restricted stock to non-employee directors prior to March 2007 vested immediately while awards granted in March 2007 are subject to three year vesting. All restricted stock awards granted to date are restricted from transfer for three years from the date of grant, whether vested or unvested. 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 years ended September 30, 2006 and 2007 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
Granted	78,314	$ 49.99
Vested	(7,300)	45.58
Forfeited	(3,200)	45.96
Unvested at September 30, 2007	160,414	$ 43.39

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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
	2005
Net income, as reported	$ 26,011
Deduct: Total stock-based
employee compensation
expense determined under fair
value based method for all
awards, net of related tax effects	(1,671)
Pro Forma, net income	$ 24,340
Earnings per share:
Basic – as reported	$ 0.86
Basic – pro forma	$ 0.80
Diluted – as reported	$ 0.83
Diluted – pro forma	$ 0.78

NOTE 4 - PROPERTY AND EQUIPMENT

A summary of property and equipment by classification is as follows (in thousands):

	September 30,
	2007	2006
Drilling vessels and related equipment
Cost	$ 778,469	$ 691,289
Accumulated depreciation	(292,790)	(261,682)
Net book value	485,679	429,607
Drill Pipe
Cost	15,587	13,271
Accumulated depreciation	(9,970)	(8,257)
Net book value	5,617	5,014
Furniture and other
Cost	9,211	7,920
Accumulated depreciation	(6,656)	(6,375)
Net book value	2,555	1,545
NET PROPERTY AND EQUIPMENT	$ 493,851	$ 436,166

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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 $7.7 million in fiscal year 2005 and is reflected as business interruption proceeds on the Consolidated Statement of Operations. The rig subsequently went back to work and continued to work through the beginning of fiscal year 2007, when we completed the remaining work to repair the rig, and recognized additional loss of hire revenue of $2.6 million, which is reflected as business interruption proceeds on the Consolidated Statement of Operations. As of September 30, 2007 and 2006, all costs incurred to date and business interruption proceeds earned related to this incident had been reimbursed by the insurance carrier.

NOTE 5 – LONG-TERM DEBT

A summary of long-term debt is as follows (in thousands):

	September 30,
	2007	2006
Credit facility, bearing interest
(market adjustable) at approximately 7% per annum
at September 30, 2007 and 2006	$ 18,000	$ 64,000
Less - current maturities	18,000	36,000
	$            -	$ 28,000

Our $250 million senior secured credit facility in place at September 30, 2007, consisted 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 that credit facility required quarterly payments of $9 million until maturity on April 1, 2008. The credit facility permitted prepayment of principal at anytime without incurring a penalty. 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 while at September 30, 2007, we had $18 million outstanding under the term portion of our credit facility and none outstanding under the revolving portion of our credit facility. The collateral at September 30, 2007 for the credit facility consisted primarily of preferred mortgages on all eight of our active drilling units (with an aggregate net book value at September 30, 2007 totaling approximately $378 million). We were not required to maintain compensating balances; however, we were 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 in place at September 30, 2007, contained 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 were in compliance with all financial covenants at September 30, 2007. Further, at all times during fiscal year 2005, 2006 and 2007 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 existed in the credit facility that could have resulted in acceleration of the April 1, 2008 maturity date.

The credit facility also supported issuance, when required, of standby letters of credit. At September 30, 2007, standby letters of credit in the aggregate amount of approximately $7.1 million were outstanding.

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Subsequent to September 30, 2007, we entered into a new credit agreement with several banks with Nordea Bank Finland PLC, New York Branch, as Administrative Agent for the lenders, as well as Lead Arranger and Book Runner. The new credit agreement provides for a secured 5-year $300,000,000 non-amortizing revolving loan facility with maturity in October 2012, subject to acceleration upon certain specified events of defaults, including breaches of representations or covenants. Loans under the new facility will bear interest at varying rates ranging from 0.70% to 1.25% over Eurodollar Rate, depending upon the ratio of outstanding debt to earnings before interest, taxes and depreciation. The new credit agreement supports the issuance, when required, of standby letters of credit. The standby letters of credit previously outstanding under our prior credit facility were incorporated into our new credit facility and are deemed issued thereunder.

The collateral for the new credit agreement consists primarily of preferred mortgages on three of our active drilling units (ATWOOD EAGLE, ATWOOD HUNTER and ATWOOD BEACON). The new credit agreement contains various financial covenants that, among other things, require the maintenance of certain leverage and interest expense coverage ratios. Under the new credit agreement, we are required to pay a fee ranging from 0.225% to 0.375% per annum on the unused portion of the credit facility and certain other administrative costs. The credit facility will provide funding for future growth opportunities and for general corporate needs. As of November 27, 2007, no funds have been borrowed under the new credit facility. In conjunction with the establishment of the new credit agreement, we terminated our prior senior secured credit facility and repaid the remaining $18 million outstanding in October 2007. We will write off the remaining unamortized loan costs of approximately $0.4 million related to the prior credit facility in the first quarter of fiscal year 2008.

NOTE 6 - INCOME TAXES

Domestic and foreign income before income taxes for the three-year period ended September 30, 2007 is as follows (in thousands):

	Fiscal	Fiscal	Fiscal
	2007	2006	2005
Domestic income (loss)	$ 8,788	$ 5,738	$ (45)
Foreign income	151,171	86,098	25,653
	$ 159,959	$ 91,836	$ 25,608

The provision (benefit) for domestic and foreign taxes on income consists of the following (in thousands):

	Fiscal	Fiscal	Fiscal
	2007	2006	2005
Current - domestic	$ 3,432	$ 58	$ (3,278)
Deferred - domestic	(1,921)	(392)	(270)
Current - foreign	19,672	6,688	2,205
Deferred - foreign	(248)	(640)	940
	$ 20,935	$ 5,714	$ (403)

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The components of the deferred income tax assets (liabilities) as of September 30, 2007 and 2006 are as follows (in thousands):

	September 30,
	2007	2006
Deferred tax assets -
Net operating loss carryforwards	$ 1,110	$ 2,550
Tax credit carryforwards	708	1,400
Stock option compensation expense	1,944	1,215
Book accruals	266	-
	4,028	5,165
Deferred tax liabilities -
Difference in book and tax basis of equipment	(16,937)	(20,553)
Unrecognized currency exchange gain	(722)	-
	(17,659)	(20,553)
Net deferred tax liabilities before valuation allowance	(13,631)	(15,388)
Valuation allowance	(708)	(640)
	$ (14,339)	$ (16,028)
Net current deferred tax assets	$ 390	$ 2,563
Net noncurrent deferred tax liabilities	(14,729)	(18,591)
	$ (14,339)	$ (16,028)

The $1.1 million of net operating loss carryforward (“NOL’s”), relates to the Australian NOL which does not expire. Management does not expect that the tax credit carryforward of $0.7 million will be utilized to offset future tax obligations before the credits begin to expire in 2012. Thus, a corresponding $0.7 million valuation allowance is recorded as of September 30, 2007. 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, 2006	$ 640
Foreign tax credit carryforwards generated	68
Valuation Allowance as of September 30, 2007	$ 708

Under SFAS 123(R), $7.3 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. The cumulative amount of such undistributed earnings was approximately $128 million at September 30, 2007. It is not practicable to estimate the amount of any deferred tax liability associated with the undistributed earnings. If these earnings were to be remitted to us, any United States income taxes payable would be substantially reduced by foreign tax credits generated by the repatriation of the earnings. Such foreign tax credits totaled approximately $57 million at September 30, 2007.

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The differences between the United States statutory and our effective income tax rate are as follows:

	Fiscal	Fiscal	Fiscal
	2007	2006	2005
Statutory income tax rate	35%	35%	35%
Resolution of prior period tax items	(1)	(7)	(23)
Decrease in tax rate resulting from -
Foreign tax rate differentials, net of foreign tax credit utilization	(21)	(22)	(14)
Effective income tax rate	13%	6%	(2%)

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 fiscal years 2007, 2006 and 2005 when compared to the United States statutory rate. There were no significant transactions that impacted our effective tax rate from the current fiscal year; however, other significant transactions that impacted our effective tax rate from prior fiscal years are as follows:

We reversed a $1.8 million tax contingent liability due to the expiration of the statute of limitations in a foreign jurisdiction during the third quarter of fiscal year 2006. In addition, 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 fiscal year 2006.

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. 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.

During July 2007, we were notified by the Malaysian tax authorities regarding a potential proposed adjustment relating to fiscal years 2000 to 2003. Although we believe we are in compliance with applicable rules and regulations, we are currently evaluating the merit of the assertions by the Malaysian tax authorities and currently plan to vigorously contest these assertions. While we cannot predict or provide assurance as to the final outcome of these allegations, we do not expect them to have a material adverse effect on our consolidated financial position, results of operations or cash flows.

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.

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Common Stock

In February 2006, our shareholders approved a proposal to increase the authorized shares of our common stock from 20,000,000 shares to 50,000,000 shares.

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 our 2006 stock split, 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, 2007, 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. After six consecutive months of service, an employee can elect to become a participant in a Plan. 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. 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 2007, 2006 and 2005, no forfeitures were utilized to reduce our cash contribution requirements. In fiscal years 2007, 2006 and 2005, our actual cash contributions totaled approximately $3.5 million, $3.1 million and $2.7 million, respectively. As of September 30, 2007, there were approximately $0.2 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 our prior credit facility (as described in Note 5) had a market adjustable interest rate, the carrying value approximated fair value as of September 30, 2007 and 2006.

39

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.

Revenues from significant customers from the prior three fiscal years are as follows (in thousands):

	Fiscal	Fiscal	Fiscal
	2007	2006	2005
Woodside Energy Ltd.	$ 68,032	$ 78,442	$ 30,757
BHP Billiton Petoleum PTY	53,410	5,151	9,070
Sarawak Shell Bhd.	50,502	32,841	24,446
Burullus Gas Company	12,991	39,053	22,118
Hoang Long & Hoan Vu Joint Operating Companies	2,800	32,114	16,557

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):

2008 $  1,644

2009     1,029

2010    854

2011    842

2012 and thereafter    2,730

Total rent expense under operating leases was approximately $3.6 million, $3.5 million and $1.8 million for fiscal years ended September 30, 2007, 2006, and 2005, 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 Financial Accounting Standards Board 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.  While we are still finalizing our evaluation of the impact of the adoption of FIN 48, we believe the adoption will result in a decrease to shareholders equity of approximately $4 to $5 million at October 1, 2007.

40

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities”, which provides companies with an option to report selected financial assets and liabilities at fair value and establishes presentation and disclosure requirements to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. GAAP has required different measurement attributes for different assets and liabilities that can create artificial volatility in earnings. The objective of SFAS No. 159 is to help mitigate this type of volatility in the earnings by enabling companies to report related assets and liabilities at fair value, which would likely reduce the need for companies to comply with complex hedge accounting provisions. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We are currently analyzing the provisions of SFAS No. 159 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 2005, the FASB issued SFAS No. 157, “Fair Value Measurements”, 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 years 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.

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.

41

A summary of revenues and operating margin for the fiscal years ended September 30, 2007, 2006 and 2005 and identifiable assets by geographic areas as of September 30, 2007, 2006 and 2005 is as follows (in thousands):

	Fiscal	Fiscal	Fiscal
	2007	2006	2005
REVENUES:
United States	$ 29,484	$ 20,249	$ 11,869
Southeast Asia & India	130,390	99,884	100,631
Mediterranean & Black Sea	112,385	68,970	23,829
Africa	65,893	27,676	-
Australia	64,885	59,846	39,827
	$ 403,037	$ 276,625	$ 176,156
OPERATING INCOME (EXPENSE):
United States	$ 8,484	$ 6,778	$ (622)
Southeast Asia & India	106,544	68,875	45,432
Mediterranean & Black Sea	27,471	25,592	2,142
Africa	27,528	4,768	-
Australia	13,109	10,393	(380)
Coporate general and administrative expenses	(23,929)	(20,630)	(14,245)
	$ 159,207	$ 95,776	$ 32,327
TOTAL ASSETS:
United States	$ 182,687	$ 69,651	$ 32,583
Southeast Asia & India	241,754	241,655	302,354
Mediterranean & Black Sea	126,214	42,447	36,980
Africa	36,074	117,760	980
Australia	121,968	117,637	115,523
General corporate and other	9,027	4,679	7,274
	$ 717,724	$ 593,829	$ 495,694

42

NOTE 14 - QUARTERLY FINANCIAL DATA (UNAUDITED)

Summarized quarterly results for fiscal years 2007 and 2006 are as follows (in thousands, except per share amounts):

	QUARTERS ENDED (1)
	December 31,	March 31,	June 30,	September 30,
Fiscal 2007
Revenues	$ 88,800	$ 94,262	$ 98,371	$ 121,604
Income before income taxes	24,463	37,618	36,569	61,309
Net income	21,085	31,757	32,033	54,149
Earnings per common share -
Basic	0.68	1.02	1.02	1.71
Diluted	0.67	1.01	1.00	1.69
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

_____

 

(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.

 

43

DIRECTORS DEBORAH A. BECK (2, 3, 4) Corporate Executive, Retired Milwaukee, Wisconsin ROBERT W. BURGESS (2, 3, 4) Financial Executive, Retired Orleans, Massachusetts GEORGE S. DOTSON (1, 2, 3, 4) Corporate Executive, Retired 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   ___________________________________________   OFFICERS JOHN R. IRWIN President, Chief Executive Officer JAMES M. HOLLAND Senior Vice President, Chief Financial Officer and Secretary GLEN P. KELLEY Senior Vice President - Marketing and Administration DARRYL SMITH Vice President - Operations ALAN QUINTERO Vice President - Engineering  

44

ANNUAL MEETING

The annual meeting of stockholders will be held at 10:00 A.M., Central Standard Time, on Thursday, February 14, 2008 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 15, 2008.

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, 2007 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 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.

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 2006 was submitted to the NYSE during fiscal year 2007, and our CEO will certify fiscal year 2007 during fiscal year 2008.

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 2006 or 2007, and none are anticipated in the foreseeable future. We have approximately 10,700 beneficial owners of our common stock based upon information provided to us by a third party shareholder services provider dated November 20, 2007. As of November 27, 2007, the closing sale price of the common stock of Atwood Oceanics, Inc., as reported by NYSE, was $76.22 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
	2007		2006
Quarters Ended	Low	High	Low	High
December 31	$ 40.72	$ 52.12	$ 32.55	$ 42.75
March 31	43.77	58.97	39.90	51.66
June 30	58.11	70.12	42.29	58.44
September 30	61.02	81.60	39.86	50.64

45

COMMON STOCK PRICE PERFORMANCE GRAPH

Below is a comparison of five (5) year cumulative total returns* among Atwood Oceanics, Inc. and the center for research in security prices (“CRSP”) index for the NYSE/AMEX/NASDAQ stock markets, and our self-determined peer group of drilling companies.

GRAPH
	Fiscal Year Ended September 30,
CRSP Total Returns Index for:	2002	2003	2004	2005	2006	2007
Atwood Oceanics, Inc.	100.0	82.0	162.5	287.9	307.5	523.5
NYSE/AMEX/Nasdaq Stock Markets	100.0	126.6	144.9	165.9	183.1	213.3
(US Companies)
Self-determined Peer Group	100.0	107.4	151.9	240.6	260.3	389.1

Constituents of the Self-Determined Peer Group (weighted according to market capitalization):

Diamond Offshore Drilling, Inc. GlobalSantaFe Corporation Rowan Companies, Inc. Transocean, Inc.

ENSCO International, Inc. Noble Corporation Pride International, Inc.

* Assumptions: (1) $100 invested on September 30, 2002; (2) dividends, if any, were reinvested; and (3) a September 30 fiscal year end.

46

BAR CHART - REVENUES ($ MILLIONS)
2003	2004	2005	2006	2007
$144.8	$163.5	$176.2	$276.6	$403.0
BAR CHART - CAPITAL EXPENDITURES ($ MILLIONS)
2003	2004	2005	2006	2007
$101.8	$6.5	$25.6	$78.5	$91.3
BAR CHART – OPERATING INCOME ($ MILLIONS)
2003	2004	2005	2006	2007
$6.5	$21.5	$32.3	$95.8	$159.2
BAR CHART - NET INCOME (LOSS) ($ MILLIONS)
2003	2004	2005	2006	2007
($12.8)	$7.6	$26.0	$86.1	$139.0

47

EX-21

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%
Alpha Leasing Drilling Limited	Mauritius	100%
Atwood Oceanics Pacific Limited	Cayman Islands, B.W.I.	100%
Alpha Offshore Drilling Services Company	Cayman Islands, B.W.I.	100%
Atwood Oceanics International Limited	Cayman Islands, B.W.I.	100%
Swiftdrill Offshore Drilling Services Company	Cayman Islands, B.W.I.	100%
Swiftdrill, Inc.	Cayman Islands, B.W.I.	100%
Atwood Oceanics Leasing Limited	Malaysia	100%
Atwood Oceanics (M) Sdn. Bhd.	Malaysia	100%
Clearways Offshore Drilling Sdn. Bhd.	Malaysia	49%
Drillquest (M) Sdn. Bhd.	Malaysia	90%
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

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. 333-74255, No. 333-87786 and No. 333-140781) and on Form S-3 (No. 333-92388 and 333-117534) of Atwood Oceanics, Inc. of our report dated November 28, 2007 relating to the consolidated financial statements and the effectiveness of internal control over financial reporting, which appears in the Annual Report to Shareholders which is incorporated in this Annual Report on Form 10-K.

/S/ PRICEWATERHOUSECOOPERS LLP

PricewaterhouseCoopers LLP

Houston, Texas

November 28, 2007

EX-31

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: November 29, 2007

/S/ JOHN R. IRWIN

John R. Irwin

Chief Executive Officer

EX-31

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: November 29, 2007

/S/ JAMES M. HOLLAND

James M. Holland

Chief Financial Officer

EX-32

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, 2007, 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. §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: November 29, 2007 /s/ John R. Irwin

John R. Irwin

President and Chief Executive Officer

EX-32

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, 2007, 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. §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: November 29, 2007                                                                                   /s/ JAMES M. HOLLAND

James M. Holland

Senior Vice President and

Chief Financial Officer