10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D. C. 20549

Form 10-K

X	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended September 30, 2008
	or
	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from _______ to ___________
	COMMISSION FILE NUMBER 1-13167
	ATWOOD OCEANICS, INC.
	(Exact name of registrant as specified in its charter)
	TEXAS (State or other jurisdiction of incorporation or organization)		74-1611874 (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:
	Title of each class			Name of each exchange on which registered
	Common Stock $1 par value Preferred Stock Purchase Rights	New York Stock Exchange New York Stock Exchange
	Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [X] No [ ]

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes [ ] No [X]

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation in S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K [ ].

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting comapny. See definition of “large accelerated filer” “accelerated filer”  and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check One):

Large accelerated filer [X]	Accelerated filer [ ]	Non-accelerated filer [ ]	Smaller Reporting Company [ ]
	(Do not check if a Smaller Reporting Company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes [ ] No [X]

The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which our Common Stock, $1 par value was last sold, or the average bid and asked price of such Common Stock, as of March 31, 2008 was $2,922,000,000.

The number of shares outstanding of our Common Stock, $1 par value, as of November 24, 2008: 64,031,480.

DOCUMENTS INCORPORATED BY REFERENCE

(1) Annual Report to Shareholders for the fiscal year ended September 30, 2008 - Referenced in Parts I, II and IV of this report.

(2) Proxy Statement for Annual Meeting of Shareholders to be held February 12, 2009 - 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 forty 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 Mediterranean Sea and the U.S. Gulf of Mexico. Approximately 97%, 93%, and 93% of our contract revenues were derived from foreign operations in fiscal years 2008, 2007 and 2006, 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 2008, filed herewith and incorporated by reference herein.

The following table presents our wholly-owned and operating rig fleet as of November 25, 2008:

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 Tender Assist	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.

Besides our current eight operating drilling units, we are also in the process of constructing three additional drilling units. We expect to complete the construction of our ninth rig, ATWOOD AURORA, (an ultra-premium jack-up) in December 2008. The total construction cost of this drilling unit (including capitalized interest and transportation costs to its first drilling location offshore Egypt) is expected to be approximately $180 million. During fiscal year 2008, we entered into construction contracts with Jurong Shipyard Pte. Ltd. to construction two Friede & Goldman ExD Millennium semisubmersible drilling units (a 6,000 feet water depth conventionally moored unit and a 10,000 feet water depth dynamically positioned unit). The conventionally moored unit is expected to cost around $600 million and is scheduled for completion in early 2011. The dynamically positioned unit is expected to cost between $750 million and $775 million and is scheduled for completion in mid 2012.

Currently, we have approximately 75% and 45% of our available rig days contracted for fiscal years 2009 and 2010, respectively, with $2 billion of revenue backlog compared to approximately $1.5 billion of estimated capital commitments for our three new units.  . For many years, one of our strategic focuses has been maintaining high equipment utilization. We had a 100% utilization rate in each of fiscal years 2008 and 2007 and have averaged over 90% utilization over the last ten years. Of our six long-term contracts for both our active units and units under construction, four are expected to extend into fiscal year 2011, one is expected to extend into fiscal year 2012, with one extending into fiscal year 2014. The ATWOOD EAGLE, ATWOOD FALCON and ATWOOD AURORA have current contract commitments extending into fiscal year 2011. The SEAHAWK's current contract commitment extends to September 2009; however, this contract provides for two six-month options which are expected to be exercised which, if exercised, will most likely extend the SEAHAWK’s contract into fiscal year 2011.  The current ATWOOD HUNTER contract is expected to extend into fiscal year 2012. Our conventionally moored semisubmersible currently under construction in Singapore has a contract that extends into fiscal year 2014 with an option which, if exercised, would extend the contract into fiscal year 2017. Our dynamically positioned semisubmersible under construction does not currently have a contract, but delivery is not expected until 2012. The current contract for the ATWOOD SOUTHERN CROSS is expected to terminate in December 2008. We are currently pursuing additional work for this unit; however, there is no guarantee that we will have work for the rig immediately following the completion of its current drilling commitment; thus, there is a possibility that the rig could incur some zero rate days. Of the other three rigs that have contracts expiring in fiscal year 2009 (the ATWOOD BEACON, VICKSBURG and RICHMOND), we expect to maintain high utilization of these rigs during fiscal year 2009.

Despite the increase in operating costs for fiscal year 2008, our operating results significantly increased for fiscal year 2008 compared to fiscal year 2007.

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 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 2008, 2007 and 2006 was 100% for each year.

     We currently expect the following planned zero rate downtime in fiscal year 2009:

RIG	ESTIMATED PERIOD IN WHICH DOWNTIME COULD OCCUR	ESTIMATED DAYS AT ZERO RATE
VICKSBURG	End of Third Quarter or Beginning of Fourth Quarter	30 Days
ATWOOD HUNTER	Fourth Quarter	10 Days
ATWOOD FALCON	Second Quarter	2 to 4 Days
SEAHAWK	During fiscal year 2009	3 to 5 Days
ATWOOD BEACON	First Quarter	3 Days

In addition to the above planned downtime, we are always at risk for unplanned downtime. During the four prior fiscal years, we have incurred approximately 1% to 2% of unplanned zero rate days per fiscal year. 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 today’s strong market environment, we are able to receive a dayrate as mobilization compensation; however, a surplus of certain types of units, either worldwide or in particular operating areas, can result in our acceptance of a contract which provides only partial or no recovery of relocation costs. Additionally, under such a contract, we may not make any profit during the relocation of a rig. 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. Any of these risks could result in damage or destruction of drilling rigs and oil and gas wells, personal injury and property damage, suspension of operations or environmental damage through oil spillage or extensive, uncontrolled fires. Therefore, in addition to general business insurance policies, we maintain the following insurance relating to our rigs and rig operations: hull and machinery, loss of hire, builder’s risk, cargo, war risks, protection and indemnity, and excess liability, among others.

Our operations are also subject to disruption due to terrorism or piracy. 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 or piracy. 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 2008, 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 4 different customers amounted to 10% or more of our revenues in fiscal year 2008 as indicated below:     

Customer	Percentage of Revenues
Petronas Carigali Sdn. Bhd	16%
ENI Spa AGIP Exploration & Production Division	15%
Sarawak Shell Bhd.	12%
Chevron Overseas Petroleum	11%

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. We believe the six members of our self-determined peer group inlcuded in our Common Stock Performance graph in our Annual Report to Shareholders filed herewith to be competitors.  The offshore drilling industry is very competitive, with no single offshore drilling contractor being dominant. Thus, there is competition in securing available offshore drilling contracts.

Price competition is generally the most important factor in the offshore drilling industry; however, when there is high worldwide utilization of equipment, as currently exists, rig availability and suitability become more important factors in securing contracts than price. The technical capability of specialized drilling equipment and personnel at the time and place required by customers are also important. Other competitive factors include work force experience, rig suitability, efficiency, condition of equipment, safety performance, reputation and customer relations. We believe that we compete favorably with respect to these factors.

Industry Trends

The performance of the offshore drilling industry is largely determined by basic supply and demand for available equipment. Periods of high demand and high dayrates are often followed by periods of low demand and low dayrates. Offshore drilling contractors can mobilize rigs from one region of the world to another, can “cold stack” rigs (taking them out of service) or reactivate cold stacked rigs in order to adjust supply of existing equipment in various markets to meet demand. The market is highly cyclical and is typically driven by general economic activity and changes in actual or anticipated oil and gas prices. Generally, sustained high energy prices translate into increased exploration and production spending by oil and gas companies, which in turn results in increased drilling activity and demand for equipment like ours.

The offshore markets where we currently operate, offshore Southeast Asia, offshore Africa, offshore India, offshore Australia, the Mediterranean Sea, and shallow waters in the U.S. Gulf of Mexico, offer the potential for continuing high utilization. Despite the decline in the price of oil and natural gas and the global financial crisis, we believe the long-term outlook for the worldwide offshore drilling industry remains positive.

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 China and in the U.S. Gulf of Mexico. Because of our experience in a number of geographic areas and the mobility of our equipment, we believe we are not dependent upon any one area of operations.  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 2006, 2007 and 2008 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 2008 was 12%. Excluding any discrete items that may occur, we expect our effective tax rate to be approximately 15% for fiscal year 2009. 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 $321 million at September 30, 2008. 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 $89 million at September 30, 2008.  For information about risks associated with our foreign operations, see Part I, Item 1A, "Risk Factors," "our relieance on foreign operatings exposes us to additional risks not generally associated with domestic operations which could have a adverse effect on our operations or financial results.

Employees

We currently employ approximately 1,200 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.

The U.S. Oil Pollution Act of 1990, or OPA, and related regulations impose a variety of requirements on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills. Few defenses exist to the liability imposed by OPA, and the liability could be substantial. Failure to comply with ongoing requirements or inadequate cooperation in the event of a spill could subject a responsible party to civil or criminal enforcement action. We have taken all steps necessary to comply with this law, and have received a Certificate of Financial Responsibility (Water Pollution) for the RICHMOND which operates in the Gulf of Mexico 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 management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements.

Important factors that could cause our actual results of operations, financial condition or cash flows to differ include, but are not necessarily limited to:

·      our dependence on the oil and gas industry;

·      the operational risks involved in drilling for oil and gas;

·      risks associated with the current global economic crisis and its impact on capital markets, liquidity, and financing of future drilling activity;

·      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 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 for our operations and those of our customers;

·      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 or the tax rate in such jurisdication, 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 including cost overruns effecting our ability to meet contractual commitments; 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 Management’s Discussion and Analysis in our Annual Report to Shareholders for fiscal year 2008 filed herewith and incorporated herein 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 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. We have adopted a code of ethics applicable to our chief executive officer and our senior financial officers which is also available on our website. We intend to satisfy the disclosure requirement regarding any changes in or waivers from our code of ethics by posting such information on our website or by filing a Form 8-K for such event. Unless stated otherwise, information on our website is not incorporated by reference into this report or made a part hereof for any purpose. You may also read and copy any document we file at the SEC’s Public Reference Room at 100F Street NE, Washington, DC 20549. Please call the SEC at 1-800-SEC-0330 for further information on the Public Reference Room 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 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 and the availability of financing for such costs;

§      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 and more recently, the price for oil and natural gas 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 dayrates and our utilization rates and, therefore, could have a material adverse effect on our financial condition, results of operations and cash flows.

THE CURRENT GLOBAL FINANCIAL CRISIS MAY HAVE A NEGATIVE IMPACT OUR BUSINESS AND FINANCIAL CONDITION

The crisis has created significant reductions in available capital and liquidity from banks and other providers of credit, which current global financial may adversely affect our customers’ and lenders’ ability to fulfill their obligations to us. In addition, continued deterioration in the global economy could result in reduced demand for crude oil and natural gas, exploration and production activity and demand for offshore drilling services which could lead to declining dayrates and a decrease of new contract activity.

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;

§      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, terrorism, and piracy. 

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, low rig availability and increasing dayrates. Periods of excess rig supply intensify the competition in the industry and often result in rigs being idled. Several markets in which we operate are currently oversupplied. Lower utilization and dayrates in one or more of the regions in which we operate would adversely affect our revenues and profitability. Prolonged periods of low utilization and dayrates could also result in the recognition of impairment charges on certain of our drilling rigs if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these rigs may not be recoverable. We may be required to idle rigs or to enter into lower-rate contracts in response to market conditions in the future.

WE RELY HEAVILY ON A SMALL NUMBER OF CUSTOMERS AND THE LOSS OF A SIGNIFICANT CUSTOMER COULD HAVE AN ADVERSE IMPACT ON OUR FINANCIAL RESULTS.

Our contract drilling business is subject to the usual risks associated with having a limited number of customers for our services. Petronas Carigali Sdn. Bhd., ENI Spa AGIP Exploration & Production Division, Sarawak Shell Bhd. and Chevron Overseas Petroleum provided approximately 16%, 15%, 12% and 11%, respectively, of our consolidated revenues in fiscal year 2008. 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 COULD INCUR DIFFICULTY IN FUNDING OUR CURRENT OR FUTURE RIG CONSTRUCTION, RIG ACQUISITION OR RIG UPGRADE PROGRAMS OR FUTURE DRILLING OPERATIONS IF WE ARE UNABLE TO OBTAIN SUFFICIENT AMOUNT OF FINANCING OR IF ONE OR MORE MEMBERS OF OUR BANK GROUP SHOULD FAIL.

Historically, we have utilized bank group financing to fund our rig construction, rig acquisition and rig upgrade programs and if needed, a portion of drilling operations. The inability to obtain sufficient amount of financing or the inability of one or more of the bank group members to provide committed funding could adversely effect our ability to complete any rig construction, rig acquisition, rig upgrade programs or drilling operations.  To-date, we have been able to obtain adequate bank group financing to fund all of our committments.

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; or

§      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. 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

§       our insurance premiums may increase to the point where maintaining our current level of coverage is prohibitively expensive or we may be unable to obtain insurance at all.

Any future accidents 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, which, in turn, would adversely effect our revenues.

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;

§      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; or

§      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 U.S. 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, TERRORISM AND PIRACY 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 through June 30, 2009. 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, terrorism or piracy could also affect our ability to raise capital and could also adversely affect the oil, gas and power industries and restrict their future growth.

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 25, 2008, Helmerich & Payne International Drilling Co., owns of record and beneficially 8,000,000 shares, or approximately 12% 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 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. 

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 2008, which is incorporated by reference herein.

Collectively since fiscal year 1997, we have expended approximately $525 million in upgrading seven offshore mobile drilling units and constructing an ultra-premium jackup unit, the ATWOOD BEACON. The timing and costs of the various upgrades and construction are as follows:

DRILLING UNITS	FISCAL YEAR UPGRADE/ CONSTRUCTION COMPLETED	COST OF UPGRADE/ CONSTRUCTION
		(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 (PHASE I)	2000		7
ATWOOD HUNTER (PHASE II)	2001		58
ATWOOD EAGLE (PHASE II)	2002		90
ATWOOD BEACON	2003		120
ATWOOD SOUTHERN CROSS (PHASE II)	2006		7
SEAHAWK (PHASE II)	2006		16
ATWOOD FALCON (PHASE II)	2006		23
RICHMOND (PHASE II)	2007		17
			$523

The ATWOOD AURORA, an ultra-premium jack-up, will become our ninth drilling unit upon expected completion of its construction in December 2008. This drilling unit is expected to have a total construction cost of approximately $180 million. The two deepwater semisubmersibles under construction in Singapore will be our tenth and eleventh drilling units upon their expected completion in early 2011 and mid-2012. These drilling units are expected to cost around $600 million and $750 to $775 million, respectively.

We have pledged the ATWOOD HUNTER, ATWOOD EAGLE, and ATWOOD BEACON as security on our $300 million credit agreement entered into in October 2007.  We have pledged the ATWOOD FALCON, ATWOOD SOUTHERN CROSS, as security for our $280 million credit agreement entered into in November 2008.  We have agreed to pledge the ATWOOD AURORA under this agreement upon delivery expected in December 2008.

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 2008, 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 7, 2008 there were approximately 12,100 beneficial owners of our common stock based upon information provided to us by a third party service provider. Our common stock and associated preferred stock purchase rights are traded on the New York Stock Exchange under the symbol “ATW”.

We did not pay cash dividends in fiscal years 2007 or 2008 and we do not anticipate paying cash dividends in the foreseeable future because of the capital-intensive nature of our business. To enable us to maintain our high competitive profile in the industry, we expect to utilize cash reserves at the appropriate time to upgrade existing equipment or to construct additional equipment. Our credit facility in place at September 30, 2008 and our new credit facility entered into in November 2008, prohibit payments of cash dividends on common stock without lender approval. In June 2008, 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 2008, which is filed herewith and 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 2008, which is filed herewith and incorporated by reference herein.

Stock Performance Graph required by this item may be found under the caption heading “Common Stock Price Performance Graph” in our Annual Report to Shareholders for fiscal year 2008, which is filed herewith and 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 2008, which is filed herewith and 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report to Shareholders for fiscal year 2008, which is filed herewith and 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of the Company’s Annual Report to Shareholders for fiscal year 2008, which is filed herewith and 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 2008, which is filed herewith and incorporated by reference herein.

ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures as of the end of the period covered by this report have been designed and are effective at the reasonable assurance level so that the information required to be disclosed by us in our periodic SEC filings is recorded, processed, summarized and reported within the time periods specific in the SEC’s rules, regulations, and forms and is communicated to management. We believe that a controls system, no matter how well designed and operated, cannot provide absolute assurance that the objectives of the controls system are met, and no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a company have been detected.

(b)   Management’s Annual Report on Internal Control over Financial Reporting

A copy of our Management’s Report of Internal Control over Financial Reporting is included in our Annual Report to Shareholders for fiscal year 2008, which is filed herewith and 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 2008, which is filed herewith and 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 12, 2009, 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 12, 2009, 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 12, 2009, 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 12, 2009, 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 ACCOUNTANT FEES AND SERVICES

This information is incorporated by reference from our definitive Proxy Statement for the Annual Meeting of Shareholders to be held February 12, 2009, to be filed with the SEC not later than 120 days after the end of the fiscal year covered by this Form 10-K.

PART IV     

ITEM 15.       EXHIBITS AND FINANCIAL STATEMENTS

                      (a)       FINANCIAL STATEMENTS AND EXHIBITS

1. and 2. FINANCIAL STATEMENTS AND SCHEDULES

The following financial statements, together with the report of PricewaterhouseCoopers LLP dated November 25, 2008 appearing in our Annual Report to Shareholders for fiscal year 2008 filed herewith, are incorporated by reference herein:

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets as of September 30, 2008 and 2007

Consolidated Statements of Operations for  years ended September 30, 2006, 2007, and 2008

Consolidated Statements of Cash Flows for for  years ended September 30, 2006, 2007, and 2008

Consolidated Statements of Changes in Shareholders' Equity for for  years ended September 30, 2006, 2007, and 2008

Notes to Consolidated Financial Statements

3.     MANAGEMENT CONTRACTS AND COMPENSATORY PLANS OR ARRANGEMENTS

                 See the "EXHIBIT INDEX" for a listing of all the Exhibits filed as a part of this report.

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.

Atwood Oceanics, Inc. Amended and Restated 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. Stock Option 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.

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

Atwood Oceanics, Inc. 2007 Long-Term Incentive Plan – See Exhibit 10.1.11 hereof.

Amendment No. 1 to Atwood Oceanics, Inc. 2007 Long-Term Incentive Plan (Incorporated by reference to Appendix B to our revised definited proxy statement on Form DEF14A filed January 15, 2008)

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

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

Form of Non-Employee Director Restricted Stock Award Agreement (2007 Long-Term Incentive Plan) – See Exhibit 10.1.15 hereof.

Atwood Oceanics, Inc. Retention Plan for Certain Salaried Employees dated effective as of January 1, 2008 – See Exhibit 10.2.1 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.

Executive Agreement dated as of June 1, 2008 between the Company and Alan Quintero – See Exhibit 10.3.4. hereof.

(b)     See the "EXHIBIT INDEX" for a listing of all of the Exhibits filed as part of this report.

(c)     NONE

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 25, 2008

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 Director
(Principal Financial and Accounting Officer)	(Principal Executive Officer)
Date: November 25, 2008	Date: November 25, 2008
/S/ ROBERT W. BURGESS	/S/ GEORGE S. DOTSON
ROBERT W. BURGESS	GEORGE S. DOTSON
Director	Director
Date: November 25, 2008	Date: November 25, 2008
/S/ HANS HELMERICH	/S/ DEBORAH A. BECK
HANS HELMERICH	DEBORAH A. BECK
Director	Director
Date: November 25, 2008	Date: November 25, 2008
/S/JAMES R. MONTAGUE
JAMES R. MONTAGUE
Director
DATE: November 25, 2008

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 for the quarter ended March 31, 2008).

3.2 Amendment No. 1 to Amended and Restated Certificate of Formation dated February 14, 2008 (Incorporated herein by reference to Exhibit 3.2. of our Form 10-Q for the quarter ended March 31, 2008).

3.3 Second Amended and Restated By-Laws dated May 5, 2006 (Incorporated herein by reference to Exhibit 3.3 of our Form 10-Q for the quarter ended March 31, 2008).

3.4 Amendment No. 1 to Second Amended and Restated By-Laws dated June 7, 2007 (Incorporated herein by reference to Exhibit 3.4 of our Form 10-Q for the quarter ended March 31, 2008).

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).

4.3 Certificate of Adjustment of Atwood Oceanics, Inc. dated as of June 25, 2008 (Incorporated herein by reference to Exhibit 4.1 of our Form 8-K filed June 25, 2008).

4.4 See Exhibit Nos. 3.1, 3.2, 3.3 and 3.4 hereof for provision of our Amended and Restated Certificate of Formation (as amended) and Second Amended and Restated By-Laws (as amended) defining the rights of our shareholders (Incorporated herein by   reference  to Exhibits 3.1, 3.2, 3.3 and 3.4 of our Form 10-Q for the quarter ended March 31, 2008).

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 of 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 Amendment No. 1 to Atwood Oceanics, Inc. 2007 Long-Term Incentive Plan (Incorporated by reference to Appendix B to our revised definited proxy statement on Form DEF14A filed January 15, 2008)

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).

10.2.1 Atwood Oceanics, Inc. Retention Plan for Certain Salaried Employees dated as of January 1, 2008. (Incorporated herein by reference to Exhibit 10.2.2 of our Form 10-K for the year ended September 30, 2007).

10.3.1  Executive Agreement dated as of September 18, 2002 between the Company and John R. Irwin (Incorporated herein by reference to Exhibit 10.5.1 of our Form 10-K for the year ended September 30, 2002).

10.3.2 Executive Agreement dated as of September 18, 2002 between the Company and James M. Holland (Incorporated herein by reference to Exhibit 10.5.2 of our Form 10-K for the year ended September 30, 2002).

10.3.3    Executive Agreement dated as of September 18, 2002 between the Company and Glen P. Kelley (Incorporated herein by reference to Exhibit 10.5.3 of our Form 10-K for the year ended September 30, 2002).

10.3.4    Executive Agreement dated as of June 1, 2008 between the Company and Alan Quintero (Incorporated herein by reference to Exhibit 10.1 of our Form 8-K filed June 9, 2008).

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).

10.4.1   First Amendment to Credit Agreement dated August 19, 2008 (Incorporated herein by reference to Exhibit 10.1 of our Form 8-K filed August 19, 2008).

10.4.2 Amended and Restated First Amendment to Credit Agreement dated November 24, 2080 (Incorporated herein by reference to Exhibit 10.1 of our Form 8-K filed November 26, 2008).

10.5    Credit Agreement for $280 million dated November 25, 2008 among the Company, Atwood Oceanics Pacific Limited and Nordea Bank Finland Plc and other Financial Institutions (Incorporated herein by reference to Exhibit 10.1.1 of our Form 8-K filed November 26, 2008).

10.6  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).

10.7  Construction Contract between Atwood Oceanics Pacific Limited and Jurong Shipyard Pte. Ltd. dated January 2, 2008 (Incorporated herein by reference to Exhibit 10.1 of our Form 8-K filed January 3, 2008).

10.8   Construction Contract between Atwood Oceanics Pacific Limited and Jurong Shipyard Pte. Ltd. dated July 4, 2008 (Incorporated herein by reference to Exhibit 10.1 of our Form 10-Q for the quarter ended June 30, 2008).

*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

EX-13

EXHIBIT 13.1

2008 ANNUAL REPORT TO SHAREHOLDERS

THE COMPANY

This Annual Report is for Atwood Oceanics, Inc. and its subsidiaries, which are collectively referred to herein 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 $520 million in upgrading seven mobile offshore drilling units and constructing an ultra-premium jack-up unit, the ATWOOD BEACON. Upon its expected delivery in December 2008, the ATWOOD AURORA will be our ninth owned, active mobile offshore drilling unit. We are also constructing a conventionally moored semisubmersible unit and a dynamically positioned semisubmersible unit, which will be our tenth and eleventh mobile offshore drilling units upon delivery in 2011 and 2012, respectively. 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

	2008	2007
	(In Thousands)
FOR THE YEAR ENDED SEPTEMBER 30:
REVENUES	$ 526,604	$ 403,037
NET INCOME	215,438	139,024
CAPITAL EXPENDITURES	328,246	88,770
AT SEPTEMBER 30:
NET PROPERTY AND EQUIPMENT	$ 787,838	$ 493,851
TOTAL ASSETS	1,099,958	717,724
TOTAL SHAREHOLDERS' EQUITY	843,690	615,855

TO OUR SHAREHOLDERS AND EMPLOYEES:

Fiscal year 2008 marked the third consecutive year of record financial results for Atwood Oceanics, Inc. and its subsidiaries (collectively the “Company”), with revenues, operating cash flows and net income being the highest in our history. Our net income of $215 million, or $3.34 per diluted share, for fiscal year 2008 reflected a 55 % improvement on our previous record net income of $139 million, or $2.18 per diluted share in fiscal year 2007. During the past fiscal year, we again achieved fleet utilization of 100% for our eight offshore drilling units and have been active in identifying and pursuing value-enhancing growth opportunities. We currently have three new rigs being constructed. Our new ultra-premium jack-up, the ATWOOD AURORA, under construction in Brownsville, Texas, will become our ninth offshore drilling unit when it commences operation on a two-year contract, currently targeted for mid-February 2009. We are also currently building two deepwater Friede & Goldman ExD Millennium design semisubmersibles at Jurong Shipyard in Singapore. These two units, which will become our tenth and eleventh drilling units, are a conventionally moored 6,000 feet water-depth unit (scheduled for delivery in early 2011 to commence a three-year contract) and a dynamically positioned 10,000 feet water-depth unit (scheduled for delivery in mid-2012).

Out of our eight drilling units currently working and the three drilling units currently under construction, five (5) have current contract commitments that extend into fiscal year 2011 or later and one (1) has options which are expected to be exercised and, if exercised, will extend the contract commitment through fiscal year 2010. We are actively pursuing additional work for the four active drilling units whose contracts will expire in fiscal year 2009 as well as work for the new build drilling unit upon its delivery in 2012. Currently, we have approximately $2 billion of revenue backlog compared to approximately $1.5 billion of estimated capital commitments for the three new units. In terms of available rig days contracted, we have approximately 75%, 45% and 35% committed for 2009, 2010 and 2011, respectively.
 
The ATWOOD BEACON has commenced drilling its final well under its current contract offshore India. This well could extend into May or June 2009. We are currently pursuing additional work for this unit outside of India. The VICKSBURG has a current contract commitment offshore Thailand that extends into June 2009. We are pursuing additional work in its current area of operations as well as other opportunities. Our only rig in the U.S. Gulf of Mexico, the RICHMOND, is currently working under a contract commitment that should extend through most of the second quarter of fiscal year 2009. The RICHMOND has been fully utilized in the Gulf of Mexico for many years and we anticipate high utilization for this rig should continue during fiscal year 2009. The ATWOOD SOUTHERN CROSS is currently working under a one-well commitment that should extend into December 2008. We are currently pursuing future opportunities for this unit.
 
The Company’s strategy is based on consistently meeting the needs of our clients with safe, quality operations; premium equipment; and being leveraged to deepwater and international markets. This strategy has served us well and continues to guide our path forward in creating value over the longer-term. Execution is a key focus for us in all respects including our financial results, operational performance and delivering, as planned, on our current three unit construction program. Based on longer term expectations for energy demand, we believe our fleet and the services we provide position the Company well to meet the future needs of our clients, especially for deepwater drilling.
 
We currently have $200 million borrowed under our five-year, $300 million credit facility, which we executed in October 2007. In November 2008, we entered into an additional five-year credit facility totaling $280 million with a potential increase up to $300 million. These credit facilities will provide funding to complete construction of the ATWOOD AURORA and the two new deepwater semisubmersibles being constructed in Singapore. It is our goal to continue to develop and position the Company for the future and to remain opportunistic in terms of identifying value enhancing opportunities when the time is right. We have no immediate plans for further growth in addition to our present three unit construction program.
 
Once again during the past fiscal year, the Company’s performance, strong position and results are owed much to the talent, hard work and contributions of both our U.S. and international employees. Accordingly, we are grateful to our employees for another successful year and to our shareholders for their trust as we continue to focus on creating longer-term value. In October 2008, we celebrated our forty-year anniversary. Atwood Oceanics is proud of its history, reputation, long-standing client relationships and the opportunity to be involved in the many communities around the world where we have been fortunate to operate.

John R. Irwin

Atwood Oceanics, Inc. and Subsidiaries

FIVE YEAR FINANCIAL REVIEW

(In thousands, except per share amounts, fleet		At or For the Years Emded September 30,
data and ratios)		2008			2007			2006			2005			2004
STATEMENTS OF OPERATIONS DATA:
Revenues	$	526,604		$	403,037		$	276,625		$	176,156		$	163,454
Contract drilling costs		(216,395	)		(186,949	)		(144,366	)		(102,849	)		(98,936	)
Depreciation		(34,783	)		(33,366	)		(26,401	)		(26,735	)		(31,582	)
General and administrative expenses		(30,975	)		(23,929	)		(20,630	)		(14,245	)		(11,389	)
Gain on sale of equipment		155			414			10,548			--			--
OPERATING INCOME		244,606			159,207			95,776			32,327			21,547
Other (expense) income		169			752			(3,940	)		(6,719	)		(9,145	)
Tax (provision) benefit		(29,337	)		(20,935	)		(5,714	)		403			(4,815	)
NET INCOME	$	215,438		$	139,024		$	86,122		$	26,011		$	7,587
PER SHARE DATA:
Earnings per common share:
Basic	$	3.38		$	2.22		$	1.39		$	0.43		$	0.14
Diluted	$	3.34		$	2.18		$	1.37		$	0.42		$	0.14
Average common shares outstanding:
Basic		63,756			62,686			61,872			60,824			55,436
Diluted		64,556			63,628			62,884			62,440			56,128
FLEET DATA:
Number of rigs owned or managed, at end
of period		8			8			10			11			11
Utilization rate for in-service rigs (1)		100	%		100	%		100	%		98	%		93	%
BALANCE SHEET DATA:
Cash and cash equivalents	$	121,092		$	100,361		$	32,276		$	18,982		$	16,416
Working capital		248,052			158,549			86,308			35,894			32,913
Net property and equipment		787,838			493,851			436,166			390,778			401,141
Total assets		1,099,958			717,724			593,829			495,694			498,936
Total long-term debt (including current portion)		170,000			18,000			64,000			90,000			181,000
Shareholders' equity (2) (3)		843,690			615,855			458,894			362,137			271,589
Ratio of current assets to current liabilities		5.12			3.75			2.41			1.64			1.55

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 4,700,000 shares of common stock in a public offering.

OFFSHORE DRILLING OPERATIONS

RIG NAME	YEAR UPGRADED	MAXIMUM WATER DEPTH	PERCENTAGE OF FY 2008 REVENUES	LOCATION AT NOVEMBER 24, 2008	CUSTOMER	CONTRACT STATUS AT NOVEMBER 24, 2008
SEMISUBMERSIBLES -
ATWOOD EAGLE	2000/2002	5,000 Ft.	17%	Offshore Australia	WOODSIDE ENERGY LTD (“WOODSIDE”)		The rig is currently working under a two year drilling program with Woodside which is expected to be completed in June 2010. Following the Woodside contract, the rig has a commitment with Chevron Australia Pty. Ltd. that will last until the expected delivery of the first new semisubmersible in February/March 2011.
ATWOOD HUNTER	1997/2001	5,000 Ft.	17%	Eastern Mediterranean Sea	NOBLE ENERGY, INC. (“NOBLE”)		The rig is currently working under a drilling program for Noble which should take until February/April 2009 to complete. Following the completion of the work in the Eastern Mediterranean Sea, the rig will be moved to West Africa to work under a long term drilling program with Noble and Kosmos Energy Ghana HC which should take until October/November 2012 to complete.
ATWOOD FALCON	1998/2006	5,000 Ft.	15%	Offshore Malaysia	SARAWAK SHELL BERHAD (“SHELL”)		The rig is currently working under a drilling program with Shell which extends to August 2009. Upon completion of the Shell program, the rig will begin a two year drilling commitment in the South China Sea.

ATWOOD SOUTHERN CROSS 1997/2006 2,000 Ft. 22% Offshore

Mauritania PETRONAS CARIGALI SDN BHD. (“PETRONAS”) The rig is currently working under a drilling commitment with Petronas which is expected to be completed in December 2008. Additional contract opportunities following the completion of this commitment are currently being pursued.  

CANTILEVER JACK-UPS –
ATWOOD BEACON	Constructed in 2003	400 Ft.	9%	Offshore India	GUJARAT STATE PETROLEUM CORPORATION LTD. (“GSPC”)	The rig is currently working under a drilling program for GSPC which extends to the completion of the well that is in progress at the end of January 2009 (estimated to be June/July 2009).
VICKSBURG	1998	300 Ft.	11%	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 December 2008. Upon delivery, the rig will be moved to offshore Egypt where it will commence a two year drilling program with RWE Dea Nile GmbH.

SUBMERSIBLE –
RICHMOND	2000/2002/2007	70 Ft.	3%	US Gulf of Mexico	CONTANGO OPERATIONS INC. (“CONTANGO”)	The rig is currently working under drilling commitments with Contango which should extend to April 2009.
SEMISUBMERSIBLE TENDER ASSIST UNIT -
SEAHAWK	1992/1999/2006	600 Ft.	6%	Offshore Equatorial Guinea	AMERADA HESS EQUATORIAL GUINEA, INC. (“HESS”)	The rig is currently working under a contractual commitment with Hess which extends to August 2009. Hess also has two six-month options remaining under this program.

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;

§      risks associated with the current global economic crisis and its impact on capital markets and liquidity and future drilling activity;

§      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 operational risks involved in drilling for oil and gas;

§      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 or piracy 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;

§      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, 2008, 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.

MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

MARKET OUTLOOK

Despite the recent decline in the price of oil and natural gas and the global financial crisis, we believe the long-term outlook for the worldwide offshore drilling industry remains positive, especially for deepwater drilling. Although, we do not anticipate any issues in the near-term resulting from the current crisis, further financial market deterioration may have a negative impact on our business and financial condition. The crisis has created significant reductions in available capital and liquidity from banks and other providers of credit, which may adversely affect our customers’ and lenders’ ability to fulfill their obligations to us. In addition, continued deterioration in the global economy could result in reduced demand for crude oil and natural gas, exploration and production activity and demand for offshore drilling services which could lead to declining dayrates and a decrease of new contract activity.

    We are currently building two semisubmersibles targeted for deepwater drilling: a conventionally moored, 6,000 feet water depth unit, (scheduled for delivery in early 2011) and a dynamically positioned, 10,000 feet water depth unit, (scheduled for delivery in mid 2012). Besides the two deepwater semisubmersible drilling units under construction, we are also in the process of completing the construction of an ultra-premium jack-up unit, the ATWOOD AURORA, scheduled for delivery in December 2008. Out of our eight drilling units currently working and the three drilling units currently under construction, five (5) have current contract commitments that extend into fiscal year 2011 or later, one (1) has options which are expected to be exercised and, if exercised, will extend the contract commitment through fiscal year 2010, four (4) have current contract commitments that expire during fiscal year 2009 and one (1) unit, without a current contract, will not be delivered until 2012. Currently, we have an estimated contract revenue backlog of approximately $2.0 billion compared to approximately $1.5 billion of estimated capital commitments for the three new builds under construction and one upgrade.

Revenues, operating cash flows and net income for fiscal year 2008 were the highest in our history. Currently, we have approximately 75% of our available rig days contracted for fiscal year 2009. A comparison of the average per day revenues for fiscal years 2008, 2007 and 2006 for each of our current eight active drilling units is as follows:

	Average Per Day Revenues
	Fiscal Year 2006	Fiscal Year 2007	Fiscal Year 2008
ATWOOD SOUTHERN CROSS	$ 82,000	$171,000	$321,000
ATWOOD BEACON	88,000	109,000	128,000
VICKSBURG	82,000	110,000	155,000
RICHMOND	55,000	81,000	44,000	(1)
ATWOOD EAGLE	129,000	160,000	241,000
ATWOOD HUNTER	172,000	234,000	246,000
ATWOOD FALCON	83,000	138,000	216,000
SEAHAWK	32,000	84,000	88,000
(1) The RICHMOND was in a shipyard undergoing a life-enhancing upgrade for approximately four months of fiscal year 2008 and earned no revenue during this time which accounts for its decline in average per day revenues.

     The ATWOOD SOUTHERN CROSS is currently working, at a dayrate of $352,000, under a one-well commitment that should extend into December 2008. We are currently pursuing additional work for this unit; however, there is no guarantee that we will have work for the rig immediately following the completion of its current drilling commitment; thus, there is a possibility that the rig could incur some zero rate days. The ATWOOD BEACON has commenced drilling its final well under its current contract offshore India that could extend into May/June 2009. We are currently pursuing additional work for this unit outside of India.  The VICKSBURG has a current contract commitment offshore Thailand at a dayrate of $154,000 that extends into June 2009. We are pursuing an extension of this contract. Our only rig in the U.S. Gulf of Mexico, the RICHMOND, is currently working under a contract commitment that should extend through most of the second quarter of fiscal year 2009 at dayrates in the mid to high $70,000's. 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 2009.

     The ATWOOD EAGLE is currently working under a contractual commitment offshore Australia at a dayrate of $405,000, subject to adjustment for cost escalations, which extends to June 2010. Following completion of this contract commitment, the rig will commence a drilling commitment that could extend for six months or longer at a dayrate of at least $430,000. The ATWOOD HUNTER has just commenced working under a drilling commitment that should extend to September 2012 at operating dayrates that range from $511,000 to $545,000, subject to adjustment for cost escalations. The ATWOOD FALCON’s current contract extends to August 2009 offshore Malaysia at a dayrate of $160,000 or $200,000, depending upon water depth of each well drilled. Following completion of this contract commitment, the rig will then commence a two-year contract commitment at a dayrate of $425,000 subject to adjustment for cost escalations. Our ultra-premium jack-up, the ATWOOD AURORA, currently under construction in Brownsville, Texas, has been awarded a two-year contract offshore Egypt. This contract provides for a dayrate of $165,000, subject to adjustment for cost escalations, with an option to extend the commitment to three years. The rig is expected to commence operations in February 2009. Our conventionally moored semisubmersible, under construction in Singapore, has been awarded a three year contract at a dayrate of $470,000, with an option to extend this commitment to six years at a dayrate of $450,000. Both dayrates are subject to adjustment for cost escalations. We expect this drilling unit will commence working offshore Australia in early 2011. The SEAHAWK is working offshore West Africa under a drilling contract that extends to September 2009, however, this contract provides for two additional six-month options at the current contracted dayrate plus certain cost escalations. The rig’s current dayrate is approximately $86,000. Despite our operating results for fiscal years 2008 and 2007 being the highest in our history, operating costs for our semisubmersible tender assist unit, SEAHAWK, exceeded revenues by approximately $4 million during fiscal year 2007 while operating costs were relatively consistent with revenues during fiscal year 2008.

     Total drilling costs for fiscal year 2008 increased 16% when compared to the prior fiscal year. With the aging workforce of the offshore drilling industry and the increasing need for personnel, we anticipate that personnel-related costs will continue to increase. We currently expect an approximate 20% increase in total drilling costs for fiscal year 2009 when compared to fiscal year 2008; however, approximately 7% of estimated fiscal year 2009 drilling costs will be due to the addition of the ATWOOD AURORA to our fleet.

     We anticipate that the VICKSBURG will be off dayrate for approximately 4 weeks to undergo an estimated $30 million equipment upgrade during June/July 2009. In addition to the estimated zero rate time for the VICKSBURG, we expect the following drilling units to incur planned zero rate time during fiscal year 2009:

ATWOOD BEACON	3 days of zero rate time during the first quarter for required regulatory inspections and maintenance
ATWOOD FALCON	2 to 4 zero rate days during the second quarter due to required regulatory inspections
SEAHAWK	3 to 5 zero rate days sometime during the fiscal year for maintenance
ATWOOD HUNTER	10 zero rate days during the fourth quarter for required regulatory inspections and maintenance

     In addition to the above planned zero rate days that could be incurred during fiscal year 2009, unplanned zero rate days can occur at any time. During the prior four fiscal years, we have incurred approximately 1% to 2% of unplanned zero rate days per year.

     Even with an expected increase in our outstanding debt to between $400 million and $500 million by the end of fiscal year 2009, we expect that our debt to total capitalization ratio will not exceed 30%. With our current contract backlog supporting a strong balance sheet, we will remain focused on executing on our current building program and on identifying value enhancing growth opportunities at the appropriate time; however, we anticipate pursuing no further growth during fiscal year 2009.

RESULTS OF OPERATIONS

Fiscal Year 2008 Versus Fiscal Year 2007

     Revenues for fiscal year 2008 increased 31% compared to the prior fiscal year. A comparative analysis of revenues by rig for fiscal years 2008 and 2007 is as follows:

	REVENUES
	(In millions)
		Fiscal		Fiscal
		Year 2008		Year 2007		Variance
ATWOOD SOUTHERN CROSS		$   117	.6	$     62	.3	$   55	.3
ATWOOD EAGLE		88	.4	58	.4	30	.0
ATWOOD FALCON		79	.0	50	.5	28	.5
VICKSBURG		56	.7	40	.0	16	.7
ATWOOD BEACON		46	.8	39	.8	7	.0
ATWOOD HUNTER		89	.9	85	.4	4	.5
SEAHAWK		32	.1	30	.6	1	.5
AUSTRALIA MANAGEMENT CONTRACTS		--		6	.5	(6	.5)
RICHMOND		16	.1	29	.5	(13	.4)
		$526	.6	$403	.0	$123	.6

     The increase in fleetwide revenues during the current fiscal year is primarily attributable to the increase in average dayrates due to improving market conditions and strong demand for offshore drilling equipment as previously discussed in “Market Outlook”. Increases in revenues during the current fiscal year for the ATWOOD SOUTHERN CROSS, ATWOOD EAGLE, ATWOOD FALCON, VICKSBURG, ATWOOD BEACON, ATWOOD HUNTER and SEAHAWK were related to each of these drilling units working at higher dayrates when compared to the prior fiscal year. The AUSTRALIA MANAGEMENT CONTRACTS were terminated during fiscal year 2007. The decrease in revenues for the RICHMOND is due to the fact that for approximately four months of the first two quarters of fiscal year 2008, the rig was in a shipyard undergoing a life-enhancing upgrade and earned no revenue during the shipyard period.

    Contract drilling costs for fiscal year 2008 increased 16% compared to the prior fiscal year. A comparative analysis of contract drilling costs by rig for fiscal years 2008 and 2007 is as follows:

	CONTRACT DRILLING COSTS
		(In millions)
			Fiscal		Fiscal
			Year 2008		Year 2007		Variance
ATWOOD SOUTHERN CROSS			$   33	.1	$   20	.7	$   12	.4
ATWOOD EAGLE			44	.5	35	.0	9	.5
VICKSBURG			18	.6	14	.0	4	.6
ATWOOD BEACON			19	.2	15	.5	3	.7
ATWOOD HUNTER			28	.9	25	.2	3	.7
SEAHAWK			30	.1	28	.2	1	.9
ATWOOD FALCON			24	.6	23	.6	1	.0
RICHMOND			12	.1	13	.1	(1	.0)
AUSTRALIA MANAGEMENT CONTRACTS			--		5	.1	(5	.1)
OTHER			5	.3	6	.5	(1	.2)
			$   216	.4	$   186	.9	$   29	.5

     On a fleetwide basis, wage increases and extra personnel for training and development have resulted in higher personnel costs, increases in the number of maintenance projects have resulted in higher equipment related costs, and overall cost inflation have led to increases in contract drilling costs during the current fiscal year for virtually every rig when compared to the prior fiscal year, including the ATWOOD SOUTHERN CROSS, ATWOOD EAGLE, VICKSBURG, ATWOOD BEACON, ATWOOD HUNTER and SEAHAWK. While the ATWOOD FALCON also incurred higher costs due to the reasons mentioned above, the increase is partially offset by a significant amount of planned maintenance performed during its water depth upgrade in the first quarter of fiscal year 2007. Contract drilling costs for the RICHMOND decreased, as the personnel-related costs increased for the reasons mentioned above was more than offset by reduced operating costs while in a shipyard undergoing a life enhancing upgrade for approximately four months of the first two quarters of fiscal year 2008. The AUSTRALIA MANAGEMENT CONTRACTS were terminated during fiscal year 2007.

     Depreciation expense for fiscal year 2008 increased 4% as compared to the prior fiscal year. A comparative analysis of depreciation expense by rig for fiscal years 2008 and 2007 is as follows:

	DEPRECIATION EXPENSE
	(In millions)
		Fiscal		Fiscal
		Year 2008		Year 2007		Variance
ATWOOD FALCON		$  5	.2	$  4	.4	$  0	.8
ATWOOD SOUTHERN CROSS		3	.7	3	.4	0	.3
ATWOOD HUNTER		5	.9	5	.7	0	.2
SEAHAWK		6	.1	6	.1	--
RICHMOND		1	.0	1	.0	--
ATWOOD EAGLE		4	.5	4	.5	--
ATWOOD BEACON		5	.1	5	.1	--
VICKSBURG		2	.8	2	.9	(0	.1)
OTHER		0	.5	0	.3	0	.2
		$  34	.8	$  33	.4	$  1	.4

     Depreciation expense has increased for the ATWOOD FALCON due to the completion of its water depth upgrade during fiscal year 2007. The increase in depreciation expense for the ATWOOD SOUTHERN CROSS when compared to the prior fiscal year is primarily due to equipment upgrades during the second half of fiscal year 2007. Depreciation expense for all other rigs has remained relatively consistent with the prior fiscal year periods. Other depreciation expense has increased due to various corporate office expenditures during the current fiscal year.

    Effective March 1, 2008, we extended the remaining depreciable life of the RICHMOND from one year to ten years, based upon completion of a life enhancing upgrade, coupled with our intent to continue marketing and operating the rig beyond one year.

     General and administrative expenses for the current fiscal year have increased compared to the prior fiscal year periods primarily due to rising personnel costs which include headcount and wage increases, increased annual bonus compensation costs, increased share-based compensation expense and increased professional fees, which include increased activity regarding future operational and global planning initiatives. While interest expense has remained relatively consistent compared to the prior fiscal year, interest income has decreased when compared to the fiscal year 2007 due to lower interest rates.

     Virtually all of our tax provision for fiscal year 2008 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 fiscal year 2008, our effective tax rate was significantly less than the United States federal statutory rate. While our effective tax rate for the current fiscal year is relatively consistent with the prior fiscal year, we anticipate that our effective rate for fiscal year 2009 will increase to approximately 15% due to a higher level of operating income earned in certain tax jurisdictions with high tax rates when compared to 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 have evaluated the merit of the assertions by the Malaysian tax authorities and are currently vigorously contesting 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.  As of September 30, 2008, there has not been any change in the status of this claim.

Fiscal Year 2007 Versus Fiscal Year 2006

     Revenues for fiscal year 2007 increased 46% compared to fiscal year 2006. 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. 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 fiscal year 2007 compared to fiscal year 2006. 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 fiscal year 2007 when compared to fiscal year 2006 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.

     Contract drilling costs for fiscal year 2007 increased 29% compared to fiscal year 2006. 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 fiscal year 2006. 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 fiscal year 2006 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 fiscal year 2006. 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 fiscal year 2007. The ATWOOD BEACON incurred higher maintenance costs in fiscal year 2007 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. Fiscal year 2007 contract drilling costs for the ATWOOD SOUTHERN CROSS have decreased primarily due to $8.6 million of mobilization expense amortization during the fiscal year 2006 compared to none during fiscal year 2007. AUSTRALIA MANAGEMENT CONTRACTS costs have decreased due to the decreased activity resulting from the completion of the most recent drilling program at the end of the first quarter of fiscal year 2007 and termination of the contracts during the third quarter of fiscal year 2007. Other drilling costs were relatively consistent with the fiscal year 2006.

     Depreciation expense for fiscal year 2007 increased 27% as compared to fiscal year 2006. 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 undergone upgrades during the fiscal years 2006 and 2007, while depreciation expense for all other rigs has remained relatively consistent with the fiscal year 2006. 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 fiscal year 2007 increased compared to fiscal year 2006 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 fiscal year 2006. 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 fiscal year 2006 compared to a gain on sale of equipment of $0.4 million during the fiscal year 2007. Interest expense has decreased during fiscal year 2007 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 fiscal year 2006 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 fiscal years 2006 and 2007, our effective tax rate for these periods was significantly less than the United States federal statutory rate. In addition, during fiscal year 2006, 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 fiscal year 2006.

LIQUIDITY AND CAPITAL RESOURCES

     As of September 30, 2008, we had $170 million outstanding under our secured 5-year $300 million revolving loan facility which matures in October 2012, subject to acceleration upon certain specified events of default, including breaches of representation or covenants. We were in compliance with all financial covenants at September 30, 2008 and at all times during fiscal year 2008, 2007 and 2006. Loans under this facility bear interest at 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 this credit facility consists primarily of preferred mortgages on three of our active drilling units (ATWOOD EAGLE, ATWOOD HUNTER and ATWOOD BEACON).

     Subsequent to September 30, 2008, we entered into another credit agreement with several banks with Nordea Bank Finland PLC, New York Branch again as Administrative Agent for the lenders, as well as Lead Arranger and Book Runner. This new credit agreement provides for a secured 5-year $280 million reducing revolving loan facility with maturity in November 2013, subject to acceleration upon certain specified events of default, including breaches of representation or covenants. The commitment under this facility may be increased by $20 million for a total commitment of $300 million.  Loans under the new facility will bear interest at 1.50% over the Eurodollar Rate at closing.  The collateral for the new credit agreement consists primarily of preferred mortgages on two of our drilling units (ATWOOD FALCON and ATWOOD SOUTHERN CROSS).  The ATWOOD AURORA will be mortgaged upon its delivery expected in December 2008.  We have collaterally assigned our interests in the ATWOOD AURORA as security for our obligations under this credit agerement between closing and delivery.

     As of November 24, 2008, we have $200 million borrowed under our 5-year $300 million credit facility and no funds borrowed under the new $280 million credit facility. Both credit facilities contain various financial covenants that, among other things, require the maintenance of certain leverage and interest expense coverage ratios. These credit facilities will provide funding to complete the construction of the ATWOOD AURORA and the two deepwater semisubmersibles being constructed in Singapore, for future growth opportunities and for general corporate needs. We expect that the total cost of the ATWOOD AURORA (including capitalized interest and transportation costs to relocate the rig to its first area of operations) will be approximately $180 million, of which approximately $20 million remains to be funded in fiscal year 2009. The total construction costs of the two deepwater semisubmersibles are expected to be approximately $600 million and $750 million, respectively. In addition to the three rigs being constructed, we also anticipate that the VICKSBURG will undergo an estimated $30 million equipment upgrade during June/July 2009.

     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 year 2002 through 2008, net cash provided by operating activities ranged from a low of approximately $14 million in fiscal year 2003 to a high of approximately $192 million in fiscal year 2008. Our operating cash flows are primarily driven by our operating income, which reflects dayrates and rig utilization. During fiscal year 2008, we used internally generated cash and funds borrowed under our $300 million credit facility to expend approximately $59 million toward the construction of the ATWOOD AURORA, approximately $17 million on a life-enhancing upgrade of the RICHMOND, approximately $238 million towards the construction of the two new deepwater semisubmersibles and approximately $14 million in other capital expenditures.

     In fiscal year 2009, we currently expect to expend approximately $20 million in completing the construction and relocation of the ATWOOD AURORA to Egypt, approximately $450 million toward the construction of the two deepwater semisubmersible and $85 million on other capital expenditures. With 75% of our available operating rig days committed for fiscal year 2009, we anticipate increases in cash flows and results of operations when compared to fiscal year 2008. We will utilize internally generated cash flows, as well as cash available under our combined $580 million credit facilities to fund our capital commitments for fiscal year 2009.

     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. The increase in accounts receivable of approximately $59 million from September 30, 2007 to September 30, 2008 is primarily attributable to several of our drilling units working under significantly higher dayrate contracts during fiscal year 2008 and to large balances due from two customers greater than 60 days outstanding as of September 30, 2008 that have since been collected during October 2008.

     The increase of inventories of materials and supplies of approximately $11 million from September 30, 2007 to September 30, 2008 is primarily due to an increased level of purchasing activity during fiscal year 2008 related to high dollar value critical spare parts for our fleet as well as an overall increase in equipment costs.

     The increase of accounts payable and accrued liabilities of approximately $5 million and $15 million, respectively, from September 30, 2007 to September 30, 2008 is primarily due to a higher amount of accrued but unpaid purchases of capital equipment related to our current construction projects and a higher amount of accrued but unpaid taxes when compared to the prior fiscal year end.

     Long-term deferred credits have decreased by approximately $16 million at September 30, 2008 compared to September 30, 2007 due to the amortization of deferred fees associated with the prior upgrades of the ATWOOD FALCON and SEAHAWK. Lump sum fees received for upgrade costs reimbursed by our customers are reported as deferred credits in our accompanying Consolidated Balance Sheets and are recognized as earned on a straight-line method over the term of the related drilling contract.

COMMITMENTS

The following table summarizes our obligations and commitments (in thousands) at September 30, 2008:

										Fiscal
		Fiscal		Fiscal		Fiscal		Fiscal		2013 and
		2009		2010		2011		2012		thereafter
Credit Facility (1)	$	-	$	-	$	-	$	170,000	$	-
Purchase Commitments (2)		450,000		270,000		260,000		100,000		--
Operating Leases		1,290		1,064		956		900		1,783
	$	451,290	$	271,064	$	260,956	$	270,900	$	1,783

(1)      Amounts exclude interest on our $300 million credit facility as interest rates are variable.

(2)      Rig construction commitments for the ATWOOD AURORA and the two new deepwater semisubmersibles.

CRITICAL ACCOUNTING POLICIES

     Significant accounting policies are included in Note 2 to our consolidated financial statements for the year ended September 30, 2008. 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.

    We currently operate eight active offshore drilling units. These assets are premium equipment and should provide many years of quality service. At September 30, 2008, the carrying value of our property and equipment totaled $787.8 million, which represents 72% 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, 2008, we have a $10.6 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 ("SFAS") 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.

     We began accounting for uncertain tax positions in accordance with FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes - an interpretation of SFAS No. 109, Accounting for Income Taxes” (FIN 48) at October 1, 2007. FIN 48 prescribes a comprehensive model for how companies should recognize, measure, present and disclose in their financial statements uncertain tax positions taken or to be taken on a tax return. The income tax laws and regulations are voluminous and are often ambiguous. As such, we are required to make many subjective assumptions and judgments regarding our tax positions that can materially affect amounts recognized in our consolidated balance sheets and statements of income.

     Effective October 1, 2005, we adopted SFAS 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. The cumulative effect on us of the change in accounting principle from APB No. 25 to SFAS 123(R) was not material.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

       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 do not anticipate that SFAS No. 159 will have a material impact 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. In February 2008, the FASB issued FASB Staff Position (“FSP”) No. FAS 157-2, “Effective Date of FASB Statement No. 157”. This FSP delays the effective date of SFAS No. 157 by one year for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). In October 2008, the FASB issued FSP FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active”. FSP FAS 157-3 clarifies the application of SFAS No. 157 in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. FSP FAS 157-3 was effective upon issuance. We do not anticipate that SFAS No. 157, FSP No. FAS 157-2 or FSP No. FAS 157-3 will have a material impact on our consolidated financial position, results of operations and cash flows.

     In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations (revised 2007)”. This statement retains the fundamental requirements for SFAS No. 141, “Business Combinations”, that the acquisition method be used for all business combinations and expands the same method of accounting to all transactions and other events in which one entity obtains control over one of more other businesses or assets at the acquisition date and in subsequent periods. SFAS No. 141(R) replaces SFAS No. 141 by requiring measurement at the acquisition date of the fair value of assets acquired, liabilities assumed and noncontrolling interest. Additionally, SFAS No. 141(R) requires that acquisition-related costs, including restructuring costs, be recognized separately from the acquisition. SFAS No. 141(R) applies prospectively to business combinations for fiscal years beginning after December 15, 2008. The impact of SFAS No. 141(R) on us will depend on the nature and extent of any future acquisitions.

     In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51”. SFAS No. 160 establishes the accounting and reporting standards for a noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. This statement clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS No. 160 requires retroactive adoption of the presentation and disclosure requirements for existing minority interests and applies prospectively to business combinations for fiscal years beginning after December 15, 2008. We are currently analyzing the provisions of SFAS No. 160 to determine 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 May 2008, the FASB, issued SFAS, No. 162, “The Hierarchy of Generally Accepted Accounting Principles”. SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP (the GAAP hierarchy). The FASB does not expect SFAS 162 to result in a change in current practice, as the intent of SFAS 162 is to direct the GAAP hierarchy to the reporting entity (rather than its auditor) and to place the GAAP hierarchy within the accounting literature established by the FASB. This statement is effective 60 days following SEC approval of the Public Company Accounting Oversight Board Amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.” We do not anticipate that SFAS 162 will have a material impact 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 our $170 million of long-term debt outstanding at September 30, 2008 was floating rate debt. As a result, our annual interest costs in fiscal year 2009 will fluctuate based on interest rate changes. Because the interest rate on our long-term debt is a floating rate, the fair value of our long-term debt approximated carrying value as of September 30, 2008. The impact on annual cash flow of a 10% change in the floating rate (approximately 35 basis points) would be approximately $0.6 million, which we believe to be immaterial. We did not have any open derivative contracts relating to our floating rate debt at September 30, 2008.

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, 2008 amounts, a decrease in the value of 10% in the foreign currencies relative to the United States Dollar from the fiscal year-end exchange rates would result in a foreign currency transaction gain of approximately $1.4 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, 2008.

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, 2008. 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, 2008. 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, 2008, 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 25, 2008
 

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, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2008 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, 2008, 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.

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 25, 2008

Atwood Oceanics, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS

		September 30,
(In thousands)		2008		2007
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	121,092	$	100,361
Accounts receivable, net of an allowance
of $114 and $164 at September 30, 2008
and 2007, respectively		135,728		76,597
Income tax receivable		3,292		1,870
Inventories of materials and supplies, net		37,906		26,721
Deferred tax assets		21		390
Prepaid expenses and deferred costs		10,225		10,240
Total Current Assets		308,264		216,179
NET PROPERTY AND EQUIPMENT		787,838		493,851
DEFERRED COSTS AND OTHER ASSETS		3,856		7,694
	$	1,099,958	$	717,724
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Current maturities of notes payable	$	-	$	18,000
Accounts payable		16,987		11,769
Accrued liabilities		42,921		27,861
Deferred credits		304		--
Total Current Liabilities		60,212		57,630
LONG-TERM DEBT,
net of current maturities:		170,000		--
		170,000		--
LONG TERM LIABILITIES:
Deferred income taxes		10,595		14,729
Deferred credits		7,942		24,093
Other		7,519		5,417
		26,056		44,239
COMMITMENTS AND CONTENGENCIES (SEE NOTE 11)
SHAREHOLDERS' EQUITY (NOTE 7):
Preferred stock, no par value;
1,000 shares authorized, none outstanding		--		--
Common stock, $1 par value, 90,000 shares
authorized with 64,031 and 63,350 issued
and outstanding at September 30, 2008
and 2007, respectively		64,031		63,350
Paid-in capital		114,804		101,549
Retained earnings		664,855		450,956
Total Shareholders' Equity		843,690		615,855
	$	1,099,958	$	717,724

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

Atwood Oceanics, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF OPERATIONS

	For Years Ended September 30,
(In thousands, except per share amounts)		2008			2007			2006
REVENUES:
Contract drilling	$	526,604		$	400,479		$	276,625
Business interruption proceeds		--			2,558			--
		526,604			403,037			276,625
COSTS AND EXPENSES:
Contract drilling		216,395			186,949			144,366
Depreciation		34,783			33,366			26,401
General and administrative		30,975			23,929			20,630
Gain on sale of equipment		(155	)		(414	)		(10,548	)
		281,998			243,830			180,849
OPERATING INCOME		244,606			159,207			95,776
OTHER INCOME (EXPENSE):
Interest expense, net of capitalized interest		(1,410	)		(1,689	)		(5,166	)
Interest income		1,579			2,441			1,226
		169			752			(3,940	)
INCOME BEFORE INCOME TAXES		244,775			159,959			91,836
PROVISION FOR INCOME TAXES		29,337			20,935			5,714
NET INCOME	$	215,438		$	139,024		$	86,122
EARNINGS PER COMMON SHARE (NOTE 2):
Basic	$	3.38		$	2.22		$	1.39
Diluted		3.34			2.18			1.37
AVERAGE COMMON SHARES OUTSTANDING (NOTE 2):
Basic		63,756			62,686			61,872
Diluted		64,556			63,628			62,884

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

Atwood Oceanics, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS

		For Years Ended September 30,
(In thousands)		2008			2007			2006
CASH FLOW FROM OPERATING ACTIVITIES:
Net income	$	215,438		$	139,024		$	86,122
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation		34,783			33,366			26,401
Amortization of debt issuance costs		657			804			804
Amortization of deferred items		(10,305	)		(25,729	)		(1,254	)
Provision for doubtful accounts		764			127			726
Provision for inventory obsolescence		290			240			--
Deferred federal income tax benefit		(3,765	)		(2,169	)		(1,032	)
Stock-based compensation expense		7,901			5,005			4,568
Gain on sale of assets		(155	)		(414	)		(10,548	)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable		(59,895	)		3,498			(41,083	)
(Increase) decrease in income tax receivable		(1,422	)		(1,805	)		3,213
Increase in inventory		(11,475	)		(4,837	)		(6,484	)
(Increase) decrease in prepaid expenses		15			(1,454	)		(5,061	)
Increase in deferred costs and other assets		(1,350	)		(4,506	)		(11,419	)
Increase in accounts payable		5,218			9			5,287
Increase in accrued liabilities		14,314			12,124			1,654
Increase in deferred credits and other liabilities		887			34,941			31,227
		(23,538	)		49,200			(3,001	)
Net Cash Provided by Operating Activities		191,900			188,224			83,121
CASH FLOW FROM INVESTING ACTIVITIES:
Capital expenditures		(328,246	)		(88,770	)		(76,133	)
Collection of insurance receivable		--			550			--
Proceeds from sale of assets		378			669			26,239
Net Cash Used by Investing Activities		(327,868	)		(87,551	)		(49,894	)
CASH FLOW FROM FINANCING ACTIVITIES:
Proceeds from debt		170,000			--			20,000
Principal payments on debt		(18,000	)		(46,000	)		(46,000	)
Debt issuance costs paid		(1,336	)		--			--
Tax benefit from the exercise of stock options		--			3,432			--
Proceeds from exercise of stock options		6,035			9,980			6,067
Net Cash Provided (Used) by Financing Activities		156,699			(32,588	)		(19,933	)
NET INCREASE IN CASH AND CASH EQUIVALENTS	$	20,731		$	68,085		$	13,294
CASH AND CASH EQUIVALENTS, at beginning of period	$	100,361		$	32,276		$	18,982
CASH AND CASH EQUIVALENTS, at end of period	$	121,092		$	100,361		$	32,276
Supplemental disclosure of cash flow information:
Cash paid during the year for domestic and foreign income taxes	$	27,421		$	13,095		$	2,654
Cash paid during the year for interest, net of amounts capitalized	$	1,342		$	1,822		$	5,033
Non-cash activities:
Increase in accrued liabilities related to capital expenditures	$	746		$	745		$	4,075

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

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, 2005	61,364	$	61,364	$	74,963		$	225,810		$	362,137
Net income	--		--		--			86,122			86,122
Restricted stock awards	10		10		(10	)		--			--
Exercise of employee stock options	718		718		5,349			--			6,067
Stock option and restricted stock
award compensation expense	--		--		4,568			--			4,568
September 30, 2006	62,092	$	62,092	$	84,870		$	311,932		$	458,894
Net income	--		--		--			139,024			139,024
Restricted stock awards	14		14		(14	)		--			--
Exercise of employee stock options	1,244		1,244		8,736			--			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	63,350	$	63,350	$	101,549		$	450,956		$	615,855
FIN 48 adoption	--		--		--			(1,539	)		(1,539	)
Net income	--		--		--			215,438			215,438
Exercise of employee stock options	681		681		5,354			--			6,035
Stock option and restricted stock
award compensation expense	--		--		7,901			--			7,901
September 30, 2008	64,031	$	64,031	$	114,804		$	664,855		$	843,690

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

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 December 2008, the ATWOOD AURORA will be our ninth owned active mobile offshore drilling unit. We are also constructing two deepwater units scheduled for delivery in 2011 and 2012, respectively. Currently, we are involved in active operations in the territorial waters of Australia, Equatorial Guinea, India, Israel, Malaysia, Mauritania, Thailand and the United States.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Consolidation

     The consolidated financial statements include the accounts of Atwood Oceanics, Inc. and all of its domestic and foreign subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.

Cash and cash equivalents

     Cash and cash equivalents consist of cash in banks and highly liquid debt instruments, which mature within three months of the date of purchase.

Foreign exchange

     The United States dollar is the functional currency for all areas of our operations. Accordingly, monetary assets and liabilities denominated in foreign currency are converted to United States dollars at the rate of exchange in effect at the end of the fiscal year, items of income and expense are remeasured at average monthly rates, and property and equipment and other nonmonetary amounts are remeasured at historical rates. Gains and losses on foreign currency transactions and remeasurements are included in contract drilling costs in our consolidated statements of operations. We recorded a foreign exchange loss of $0.1 million during both fiscal years 2008 and 2006 while we did not record a foreign exchange gain or loss during fiscal year 2007.

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, 2008 and 2007 are unbilled receivable balances totaling $13.3 million and $13.1 million, respectively, that represent 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 their respective 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 $0.1 million and $0.2 million, as of September 30, 2008 and 2007, respectively.

Inventories of Material and Supplies

     Inventories consist of spare parts, material and supplies held for consumption and are stated principally at the lower of average cost or market, net of reserves for excess and obsolete inventory of $1.3 million and $1.2 million at September 30, 2008 and 2007, 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 2008, 2007 and 2006 was $2.6 million, $2.6 million and $1.6 million, respectively.

     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

     Effective March 1, 2008, we extended the remaining depreciable life of the RICHMOND from one year to ten years, based upon completion of a life enhancing upgrade, coupled with our intent to continue marketing and operating the rig beyond one year.

     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. There were no impairments during fiscal years ended September 20, 2008, 2007 or 2006.

Deferred drydocking costs

     We defer the costs of scheduled drydocking and charge such costs to contract drilling expense over the period to the next scheduled drydocking (normally 30 months). At September 30, 2008 and 2007, deferred drydocking costs totaling $1.8 million and $1.9 million, respectively, were included in Deferred Costs and Other Assets in the accompanying Consolidated Balance Sheets.

Revenue recognition

     We account for drilling and management contract revenue in accordance with the term of the underlying drilling or management contract. These contracts generally provide that revenue is earned and recognized on a daily basis. We provide crewed rigs to customers on a daily rate (i.e. “dayrate”) basis. Dayrate contracts can be for a specified period of time or the time required to drill a specified well or number of wells. Revenues from dayrate drilling operations, which are classified under contract drilling services, are recognized on a per day basis as the work progresses. In addition, business interruption proceeds are also recognized on a per day basis. See Note 4 for further discussion of the ATWOOD BEACON incident.

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, 2008 and 2007, deferred fees associated with mobilization as well as related equipment purchases and upgrades totaled $8.2 million and $24.1 million, respectively. At September 30, 2008 and 2007, deferred costs associated with mobilization and related equipment purchases and upgrades totaled $0.3 million and $4.8 million, respectively. Deferred fees and deferred costs are classified as current or long-term deferred credits and deferred costs, respectively, 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. 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.

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 2008:
Basic earnings per share	$	215,438	63,756	$	3	.38
Effect of dilutive securities –
Stock options		--	800		(0	.04)
Diluted earnings per share	$	215,438	64,556	$	3	.34
Fiscal 2007:
Basic earnings per share	$	139,024	62,686	$	2	.22
Effect of dilutive securities –
Stock options		--	942		(0	.04)
Diluted earnings per share	$	139,024	63,628	$	2	.18
Fiscal 2006:
Basic earnings per share	$	86,122	61,872	$	1	.39
Effect of dilutive securities –
Stock options		--	1,012		(0	.02)
Diluted earnings per share	$	86,122	62,884	$	1	.37

    The calculation of diluted earnings per share for the years ended September 30, 2008 and 2006 exclude consideration of shares of common shares which may be issued in connection with outstanding stock options of 184,000 and 250,000, respectively, because such options were antidilutive. These options could potentially dilute basic EPS in the future. For the fiscal year ended September 30, 2007, 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. 

Reclassifications

     Certain reclassifications have been made to the prior period financial statements to conform to the current year presentation.  These reclassifications did not affect the Consolidated Balance Sheets or Consolidated Statements of Operations reported in the prior fiscal year.

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. The cumulative effect of the change in accounting principle from APB No. 25 to FAS 123(R) was not material.

     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, as amended, 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 4,000,000 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 approved by our shareholders, 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, 2008 is as follows:

	2007	2001	1996
	Plan	Plan	Plan
Shares available for future awards or grants	3,539,208	--	--
Outstanding stock option grants	183,928	939,128	130,022
Outstanding unvested restricted stock awards	276,864	304,500	--

     Awards of restricted stock and stock options have both been granted under our stock incentive plans as of September 30, 2008. 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,
		2008			2007			2006
Increase in contract drilling expenses	$	2,095		$	1,277		$	840
Increase in general and administrative expenses		5,806			3,728			3,728
Decrease in income tax provision		(2,032	)		(1,305	)		(1,305	)
Decrease in net income		5,869			3,700			3,263
Decrease in earnings per share:
Basic	$	0.09		$	0.06		$	0.05
Diluted	$	0.09		$	0.06		$	0.05

 

     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 (in thousands, except average service periods):

	September 30,
		2008		2007
Unrecognized Compensation Cost
Stock options	$	4,414	$	3,674
Restricted stock awards		10,072		3,902
Total	$	14,486	$	7,576
Remaining weighted average service period (Years)		2.6		2.1

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, 2008, 2007 and 2006 was $2.4 million, $2.1 million and $3.2 million, respectively. The per share weighted average fair value of stock options granted during years ended September 30, 2008, 2007 and 2006 was $20.34, $11.82 and $8.94, 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
	2008		2007		2006
Risk-Free Interest Rate	3.7	%	4.5	%	4.5	%
Expected Volatility	46	%	46	%	42	%
Expected Life (Years)	5.3		5.3		6.0
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 six year historical volatility figure and determined the expected term of the stock options using 10 years of historical data. The expected dividend yield is based on the expected annual dividend as a percentage of the market value of our common stock as of the grant date.

A summary of stock option activity for year ended September 30, 2008 is as follows:

						Wtd. Avg.
				Wtd. Avg.		Remaining			Aggregate
	Number of			Exercise		Contractual			Intrinsic
	Options			Price		Life (Years)			Value (000	s)
Outstanding at October 1, 2007	1,762,776		$	12	.27
Granted	187,128			44	.75
Exercised	(681,326	)		8	.86			$	27,346
Forfeited	(15,500	)		24	.88
Outstanding at September 30, 2008	1,253,078		$	18	.82	6	.5	$	22,035
Exercisable at September 30, 2008	699,050		$	12	.26	5	.5	$	16,872

 

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 a vesting period ranging from three to four years. Awards of restricted stock to non-employee directors during fiscal year 2006 vested immediately while awards granted subsequent to fiscal year 2006 are subject to a vesting period ranging from one to three years. All restricted stock awards granted to date are restricted from transfer for at least three or four 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 year ended September 30, 2008 is as follows:

	Number of		Wtd. Avg.
	Shares		Fair Value
Unvested at October 1, 2007	320,828		$	21	.70
Granted	277,312			44	.74
Vested	--			--
Forfeited	(16,776	)		28	.36
Unvested at September 30, 2008	581,364		$	32	.50

NOTE 4 - PROPERTY AND EQUIPMENT

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

	September 30,
		2008			2007
Drilling vessels and related equipment
Cost	$	1,106,709		$	778,469
Accumulated depreciation		(324,376	)		(292,790	)
Net book value		782,333			485,679
Drill Pipe
Cost		15,568			15,587
Accumulated depreciation		(12,139	)		(9,970	)
Net book value		3,429			5,617
Furniture and other
Cost		9,423			9,211
Accumulated depreciation		(7,347	)		(6,656	)
Net book value		2,076			2,555
NET PROPERTY AND EQUIPMENT	$	787,838		$	493,851

     As of September 30, 2008, we had approximately $152 million, $125 million and $113 million of construction in progress related to the construction of the ATWOOD AURORA, the new conventionally moored semisubmersible project, and the new dynamically positioned semisubmersible project, respectively.  The total cost of the ATWOOD AURORA is expected to be $180 million, including transportation costs to its initial location, with delivery expected in December 2008.

New Semisubmersible Construction Projects

     In January 2008 and July 2008, we executed construction contracts with Jurong Shipyard Pte. Ltd. to construct a conventionally moored Friede & Goldman ExD Millennium Semisubmersible Drilling Unit and a dynamically positioned Friede & Goldman ExD Millennium Semisubmersible Drilling Unit with deliveries expected to occur in early 2011 and mid 2012, respectively. We estimate the total costs of the conventionally moored rig will be approximately $600 million while the cost to construct the dynamically positioned rig is expected to be approximately $750 million.

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. 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 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, all reimbursable 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,
	2008		2007
Credit facility, bearing interest
(market adjustable) at approximately 3.5% and 7% per
annum at September 30, 2008 and 2007, respectively	$	170,000	$	18,000
Less - current maturities		--		18,000
	$	170,000	$	-

     During October 2007, we entered into a 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. Our credit agreement provides for a secured 5-year $300 million revolving loan facility with maturity in October 2012, subject to acceleration upon certain specified events of default, including breaches of representations or covenants. Loans under this 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 credit agreement supports the issuance, when required, of standby letters of credit. The standby letters of credit outstanding under our prior credit facility were incorporated into this credit facility and were deemed issued thereunder.

     The collateral for this $300 million credit agreement consists primarily of preferred mortgages on three of our active drilling units: ATWOOD EAGLE, ATWOOD HUNTER and ATWOOD BEACON with an aggregate net book value at September 30, 2008 totaling approximately $249 million. This credit agreement contains various financial covenants that, among other things, require the maintenance of certain leverage and interest expense coverage ratios. Under this 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. As of September 30, 2008, we have $130 million of funds available to borrow under this credit facility.

     At September 30, 2008, standby letters of credit in the aggregate amount of approximately $5.3 million were outstanding under this $300 million credit agreement.

     In conjunction with the establishment of the $300 million credit agreement in 2007, we terminated our prior senior secured credit facility and repaid the remaining $18 million outstanding as of September 30, 2007 during October 2007. We also wrote off to interest expense the remaining unamortized loan costs of approximately $0.4 million related to the prior credit facility during the quarter ended December 31, 2007. In addition, we paid approximately $1.3 million of debt issuance costs related to the current credit facility during the fiscal year 2008 which will be amortized over the term this credit facility.

      Subsequent to September 30, 2008, we entered into another credit agreement with several banks with Nordea Bank Finland plc, New York Branch again as Administrative Agent for the lenders, as well as Lead Arranger and Book Runner. This new credit agreement provides for a secured 5-year $280 million reducing revolving loan facility with maturity in November 2013, subject to acceleration upon certain specified events of default, including breaches of representation or covenants. The commitment under this facility may be increased by $20 million for a total commitment of $300 million.  Loans under the new facility will bear interest at 1.50% over the Eurodollar Rate at closing.  The collateral for the new credit agreement consists primarily of preferred mortgages on two of our drilling units (ATWOOD FALCON and ATWOOD SOUTHERN CROSS).  The ATWOOD AURORA will be mortgaged upon its expected delivery in December 2008.  We have collaterally assigned our interests in the ATWOOD AURORA as security for our obligations under this credit agerement between closing and delivery.  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 along with the $300 million credit facility established in 2007 will provide funding for the three drilling units currently under construction (including the ATWOOD AURORA), for future growth opportunities and for general corporate needs. As of November 24, 2008, $200 million has been borrowed under the $300 million credit facility, with no funds borrowed under the new $280 million credit facility.

NOTE 6 - INCOME TAXES

Domestic and foreign income before income taxes for the three-year period ended September 30, 2008 is as follows (in thousands):

	Fiscal			Fiscal		Fiscal
	2008			2007		2006
Domestic income (loss)	$	(6,480	)	$	8,788	$	5,738
Foreign income		251,255			151,171		86,098
	$	244,775		$	159,959	$	91,836

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

	Fiscal			Fiscal			Fiscal
	2008			2007			2006
Current - domestic	$	209		$	3,432		$	58
Deferred - domestic		(3,555	)		(1,921	)		(392	)
Current - foreign		32,893			19,672			6,688
Deferred - foreign		(210	)		(248	)		(640	)
	$	29,337		$	20,935		$	5,714

 

The components of the deferred income tax assets (liabilities) as of September 30, 2008 and 2007 are as follows (in thousands): 

	September 30,
		2008			2007
Deferred tax assets -
Net operating loss carryforwards	$	618		$	1,110
Tax credit carryforwards		730			708
Stock option compensation expense		3,575			1,944
Book accruals		1,412			266
		6,335			4,028
Deferred tax liabilities -
Difference in book and tax basis of equipment		(16,179	)		(16,937	)
Unrecognized currency exchange gain		--			(722	)
		(16,179	)		(17,659	)
Net deferred tax liabilities before valuation allowance		(9,844	)		(13,631	)
Valuation allowance		(730	)		(708	)
	$	(10,574	)	$	(14,339	)
Net current deferred tax assets	$	21		$	390
Net noncurrent deferred tax liabilities		(10,595	)		(14,729	)
	$	(10,574	)	$	(14,339	)

     The $0.6 million of net operating loss carryforward (“NOL’s”), relates to a United States NOL which expires in 2028. 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, 2008. 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, 2007	$	708
Foreign tax credit carryforwards generated		22
Valuation Allowance as of September 30, 2008	$	730

     Under SFAS 123(R), $16.6 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 $321 million at September 30, 2008. 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 $89 million at September 30, 2008.

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

	Fiscal		Fiscal		Fiscal
	2008		2007		2006
Statutory income tax rate	35	%	35	%	35	%
Resolution of prior period tax items	--		(1	)	(7	)
Decrease in tax rate resulting from -
Foreign tax rate differentials, net of foreign tax credit utilization	(23	)	(21	)	(22	)
Effective income tax rate	12	%	13	%	6	%

     We adopted the provision of FASB Interpretation No. 48 "Accounting for Uncertainty in Income Taxes - an interpretation of SFAS No. 109, Accounting for Income Taxes", or FIN 48, on October 1, 2007. As a result of the implementation of FIN 48, we recognized an approximate $1.5 million increase in the long-term liability for uncertain tax positions which was accounted for as a reduction to the October 1, 2007 balance of retained earnings. After the adoption of FIN 48, we had $3.7 million of reserves for uncertain tax positions, including estimated accrued interest and penalties of $1.7 million as of October 1, 2007 which are included as Other Long Term Liabilities in the Consolidated Balance Sheet.

     We record estimated accrued interest and penalties related to uncertain tax positions in income tax expense. At September 30, 2008, we had $3.5 million of reserves for uncertain tax positions, including estimated accrued interest and penalties of $1.0 million which are included as Other Long Term Liabilities in the Consolidated Balance Sheet. All $3.5 million of the net unrecognized tax benefits would affect the effective tax rate if recognized. A summary of activity related to the net unrecognized tax benefits including penalties and interest for fiscal year 2008 is as follows:

	Liability for Uncertain
	Tax Positions
Balance at October 1, 2007	$	3,734
Increases based on tax positions related to prior fiscal years		157
Decreases based on tax positions related to prior fiscal years		(1,842	)
Increases based on tax positions related to current fiscal year		1,443
Balance at September 30, 2008	$	3,492

     Our United States tax returns for fiscal year 2006 and subsequent years remain subject to examination by tax authorities. As we conduct business globally, we have various tax years remaining open to examination in our international tax jurisdictions. We do not anticipate that any tax contingencies resolved during the next 12 months will have a material impact on our consolidated financial position, results of operations or cash flows.

     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 2008, 2007 and 2006 when compared to the United States statutory rate. There were no significant transactions that materially impacted our effective tax for fiscal year 2008 or 2007; however, during fiscal year 2006, the significant transactions that materially impacted our effective tax rate 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 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 have evaluated the merit of the assertions by the Malaysian tax authorities and are currently vigorously contesting 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.  As of September 30, 2008, there has not been any change in the status of this claim.

NOTE 7 - CAPITAL STOCK

Preferred Stock

     In 1975, 1,000,000 shares of preferred stock with no par value were authorized. In October 2002, we designated Series A Junior Participating Preferred Stock. No preferred shares have been issued.

Common Stock

     On June 11, 2008, our board of directors declared a two-for-one stock split of our common stock effected in the form of a 100% common stock dividend. All shareholders of record at the close of business on June 27, 2008 (the “Record Date”), were entitled to receive on the distribution date, July 11, 2008 (the “Distribution Date”), one additional share of common stock for each share held on the Record Date. The additional shares of common stock were distributed in the form of a 100% common stock dividend on the Distribution Date. All share and per share amounts in the accompanying consolidated financial statements and related notes have been adjusted to reflect the stock split for all periods presented.

Rights Agreement

     In September 2002, we authorized and declared a dividend of one Right (each 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 (each 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 2008 stock split, and in accordance with the Rights Agreement, we decreased from one two-thousandth to one four-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 $0.005 to $0.0025 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, 2008, 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 one month 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 2008, 2007 and 2006, no forfeitures were utilized to reduce our cash contribution requirements. In fiscal years 2008, 2007 and 2006, our actual cash contributions totaled approximately $4.3 million, $3.5 million and $3.1 million, respectively. As of September 30, 2008, there were approximately $0.3 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 credit facilities (as described in Note 5) have market adjustable interest rates, the carrying value approximated fair value as of September 30, 2008 and 2007.

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.

     Despite the recent decline in the price of oil and natural gas and the global financial crisis, we believe long-term outlook for the worldwide offshore drilling industry remains positive, especially for deepwater drilling. Although, we do not anticipate any issues in the near-term resulting from the current crisis, further financial market deterioration may have a negative impact on our business and financial condition. The crisis has created significant reductions in available capital and liquidity from banks and other providers of credit, which may adversely affect our customers’ and lenders’ ability to fulfill their obligations to us. In addition, continued deterioration in the global economy could result in reduced demand for crude oil and natural gas, exploration and production activity and demand for offshore drilling services which could lead to declining dayrates and a decrease of new contract activity.

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

		Fiscal		Fiscal		Fiscal
		2008		2007		2006
Petronas Carigali Sdn Bhd	$	60,182	$	1,713	$	15,809
ENI Spa AGIP Exploration & Production Division		83,308		445		18,753
Sarawak Shell Bhd.		78,988		50,502		32,841
Chevron Overseas Petroleum		56,712		38,272		--
Woodside Energy Ltd.		37,542		68,032		78,442
BHP Billiton Petoleum PTY		34,431		53,410		5,151
Burullus Gas Company		29,690		12,991		39,053
Hoang Long & Hoan Vu Joint Operating Companies		--		2,800		32,114

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):

2009	......................................	1,290
2010	......................................	1,064
2011	......................................	956
2012	......................................	900
2013	and thereafter ................	1,783

Total rent expense under operating leases was approximately $4.8 million, $3.6 million and $3.5 million for fiscal years ended September 30, 2008, 2007, and 2006, 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.

Other Matters

     In one of the foreign jurisdictions where we operate, a new operating tax on drilling services was enacted during fiscal year 2007. In our opinion, which is supported by our legal and tax advisors, we believe the liability related to this new service tax is a direct obligation of our customer according to the provisions of the tax law in the foreign jurisdiction. Additionally, our contract terms provide for this tax to be paid by our customer. To date, there have been no assessments against us or payments made relating to this service tax.

NOTE 12 – RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

     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 do not anticipate that SFAS No. 159 will have a material impact 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. In February 2008, the FASB issued FASB Staff Position (“FSP”) No. FAS 157-2, “Effective Date of FASB Statement No. 157”. This FSP delays the effective date of SFAS No. 157 by one year for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). In October 2008, the FASB issued FSP FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active”. FSP FAS 157-3 clarifies the application of SFAS No. 157 in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. FSP FAS 157-3 was effective upon issuance. We do not anticipate that SFAS No. 157, FSP No. FAS 157-2 and FSP No. FAS 157-3 will have a material impact on our consolidated financial position, results of operations and cash flows.

     In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations (revised 2007)”. This statement retains the fundamental requirements for SFAS No. 141, “Business Combinations”, that the acquisition method be used for all business combinations and expands the same method of accounting to all transactions and other events in which one entity obtains control over one of more other businesses or assets at the acquisition date and in subsequent periods. SFAS No. 141(R) replaces SFAS No. 141 by requiring measurement at the acquisition date of the fair value of assets acquired, liabilities assumed and noncontrolling interest. Additionally, SFAS No. 141(R) requires that acquisition-related costs, including restructuring costs, be recognized separately from the acquisition. SFAS No. 141(R) applies prospectively to business combinations for fiscal years beginning after December 15, 2008. The impact of SFAS No. 141(R) on us will depend on the nature and extent of any future acquisitions.

     In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51”. SFAS No. 160 establishes the accounting and reporting standards for a noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. This statement clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS No. 160 requires retroactive adoption of the presentation and disclosure requirements for existing minority interests and applies prospectively to business combinations for fiscal years beginning after December 15, 2008. We are currently analyzing the provisions of SFAS No. 160 to determine 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 May 2008, the FASB, issued SFAS, No. 162, “The Hierarchy of Generally Accepted Accounting Principles”. SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP (the GAAP hierarchy). The FASB does not expect SFAS 162 to result in a change in current practice, as the intent of SFAS 162 is to direct the GAAP hierarchy to the reporting entity (rather than its auditor) and to place the GAAP hierarchy within the accounting literature established by the FASB. This statement is effective 60 days following SEC approval of the Public Company Accounting Oversight Board Amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.” We do not anticipate that SFAS 162 will have a material impact 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.

A summary of revenues and operating margin for the fiscal years ended September 30, 2008, 2007 and 2006 and identifiable assets by geographic areas as of September 30, 2008, 2007 and 2006 is as follows (in thousands):

		Fiscal			Fiscal			Fiscal
		2008			2007			2006
REVENUES:
United States	$	16,096		$	29,484		$	20,249
Southeast Asia & India		182,503			130,390			99,884
Mediterranean & Black Sea		141,414			112,385			68,970
Africa		98,188			65,893			27,676
Australia		88,403			64,885			59,846
	$	526,604		$	403,037		$	276,625
OPERATING INCOME (EXPENSE):
United States	$	(1,891	)	$	8,484		$	6,778
Southeast Asia & India		108,030			106,544			68,875
Mediterranean & Black Sea		103,934			27,471			25,592
Africa		35,336			27,528			4,768
Australia		30,172			13,109			10,393
Corporate general and administrative expenses		(30,975	)		(23,929	)		(20,630	)
	$	244,606		$	159,207		$	95,776
TOTAL ASSETS:
United States	$	208,597		$	182,687		$	69,651
Southeast Asia & India		494,420			241,754			241,655
Mediterranean & Black Sea		78,492			126,214			42,447
Africa		110,629			36,074			117,760
Australia		152,031			121,968			117,637
Other		55,789			9,027			4,679
	$	1,099,958		$	717,724		$	593,829

 

NOTE 14 - QUARTERLY FINANCIAL DATA (UNAUDITED)

Summarized quarterly results for fiscal years 2008 and 2007 are as follows (in thousands, except per share amounts):

	QUARTERS ENDED (1)
		December 31,		March 31,		June 30,		September 30,
Fiscal 2008
Revenues	$	111,048	$	113,530	$	141,372	$	160,654
Income before income taxes		43,111		46,354		68,066		87,244
Net income		38,549		41,755		60,381		74,753
Earnings per common share -
Basic		0.61		0.66		0.94		1.17
Diluted		0.60		0.65		0.93		1.16
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		0.34		0.51		0.51		0.86
Diluted		0.34		0.51		0.50		0.85

_____

(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.

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 (2, 3, 4)
Corporate Executive, Retired
Houston, Texas (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 ALAN QUINTERO Senior Vice President - Operations RONNIE L. HALL Vice President - Operations BARRY M. SMITH Vice President - Technical Services RANDAL F. PRESLEY Vice President - Administrative Services

ANNUAL MEETING

     The annual meeting of stockholders will be held at 10:00 A.M., Central Standard Time, on Thursday, February 12, 2009 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 13, 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

SEC FILINGS

     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, 2008 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 room and copy charges.

NYSE CERTIFICATION

     Each year, our CEO must certify to the NYSE that he is not aware of any violations by the Company of NYSE corporate governance listing standards. Our CEO’s certification for fiscal year 2007 was submitted to the NYSE during fiscal year 2008, and our CEO will certify fiscal year 2008 during fiscal year 2009.

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 2007 or 2008, and none are anticipated in the foreseeable future. We have approximately 12,100 beneficial owners of our common stock based upon information provided to us by a third party shareholder services provider dated November 7, 2008. As of November 24, 2008, the closing sale price of the common stock of Atwood Oceanics, Inc., as reported by NYSE, was $19.09 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
	2008				2007
Quarters Ended	Low		High		Low		High
December 31	$     35	.75	$  51	.84	$   20	.36	$  26	.06
March 31	36	.39	52	.70	21	.89	29	.49
June 30	44	.56	62	.95	29	.06	35	.06
September 30	32	.25	63	.46	30	.51	40	.80

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 DATA	Fiscal Year Ended September 30,
CRSP Total Returns Index for:	2003		2004		2005		2006		2007		2008
Atwood Oceanics, Inc.	100	.0	198	.2	351	.0	374	.9	638	.3	606	.9
NYSE/AMEX/Nasdaq Stock Markets	100	.0	114	.4	131	.1	144	.6	168	.5	133	.2
(US Companies)
Self-determined Peer Group +	100	.0	145	.3	233	.0	250	.9	375	.5	346	.5
Atwood Ocenaics, Inc.		.

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

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

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

* Assumptions: (1) $100 invested on September 30, 2003; (2) dividends, if any, were reinvested; and (3) a September 30 fiscal year end.

BAR CHART - REVENUES ($ MILLIONS)
2004	2005	2006	2007	2008
$163.5	$176.2	$276.6	$403.0	$ 526.6
BAR CHART - CAPITAL EXPENDITURES ($ MILLIONS)
2004	2005	2006	2007	2008
$ 6.5	$ 25.6	$ 76.1	$ 88.8	$ 328.2
BAR CHART – OPERATING INCOME ($ MILLIONS)
2004	2005	2006	2007	2008
$ 21.5	$ 32.3	$ 95.8	$159.2	$ 244.6
BAR CHART - NET INCOME ($ MILLIONS)
2004	2005	2006	2007	2008
$ 7.6	$ 26.0	$ 86.1	$139.0	$ 215.4

EX-21

Exhibit 21.1

ATWOOD OCEANICS, INC.

SUBSIDIARY AND AFFILIATED COMPANIES, STATE OR
JURISDICTION OF INCORPORATION AND OWNERSHIP PERCENTAGE

Alpha Leasing Drilling Limited	Mauritius	100	%
Alpha Offshore Drilling (Cambodia) ltd.	Cambodia	100	%
Alpha Offshore Drilling (S) Pte. Ltd.	Singapore	100	%
Alpha Offshore Drilling Services Company	Cayman Islands	100	%
Alpha Offshore Drilling Services Company - Free Zone	Egypt	100	%
ATW Management, Inc.	Delaware	100	%
Atwood Deep Seas, Ltd. (Partnership)	Texas	100	%
Atwood Drilling, Inc.	Delaware	100	%
Atwood Hunter Co.	Delaware	100	%
Atwood Management, Inc.	Delaware	100	%
Atwood Oceanics Australia Pty Limited	Australia	100	%
Atwood Oceanics Drilling Pty	Australia	100	%
Atwood Oceanics International Limited	Cayman Islands	100	%
Atwood Oceanics Leasing Ltd.	Malaysia	100	%
Atwood Oceanics (M) Sdn. Bhd.	Malaysia	100	%
Atwood Oceanics Malta Ltd.	Malta	100	%
Atwood Oceanics Management, LP (Partnership)	Delaware	100	%
Atwood Oceanics (NZ) Limited	New Zealand	100	%
Atwood Oceanics Pacific Limited	Cayman Islands	100	%
Atwood Oceanics Platforms Pty Ltd.	Australia	100	%
Atwood Oceanics Services	Singapore	100	%
Atwood Oceanics Services Pty Ltd.	Australia	100	%
Atwood Oceanics West Tuna Pty Ltd.	Australia	100	%
Atwood Offshore Drilling Ltd.	Hong Kong	100	%
Aurora Offshore Services Gmb	Germany	100	%
Clearways Offshore Drilling Sdn. Bhd.	Malaysia	49	%
Drillquest (M) Sdn. Bhd.	Malaysia	100	%
PT Alpha Offshore Drilling	Indonesia	100	%
PT Pentawood Offshore Drilling	Indonesia	80	%
Swiftdrill, Inc.	Cayman Islands	100	%
Swiftdrill Nigeria Limited	Nigeria	60	%
Swiftdrill Offshore Drilling Services Company	Cayman Islands	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, as amended, and 333-117534) of Atwood Oceanics, Inc. of our report dated November 25, 2008 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 filed hwerewith and  incorporated in this Annual Report on Form 10-K.

 

 

 

/S/ PRICEWATERHOUSECOOPERS LLP
PricewaterhouseCoopers LLP

   

Houston, Texas
November 25, 2008

 

 

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 25, 2008

/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 25, 2008

/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, 2008, 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 25, 2008	/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, 2008, 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 25, 2008	/S/ JAMES M. HOLLAND
	James M. Holland
	Senior Vice President and
	Chief Financial Officer