May 24, 2017

VIA HAND DELIVERY AND EDGAR

Securities and Exchange Commission

Division of Corporation Finance

100 F Street, N.E.

Mail Stop 7010

Washington, D.C. 20549-6628

Attn: Mr. Brad Skinner, Division of Corporation Finance

Re: Atwood Oceanics, Inc.

Form 10-K for the Fiscal Year ended September 30, 2016

Filed November 15, 2016

File No. 001-13167

Dear Mr. Skinner:

With respect to the comments of the staff to the captioned filing (the “Staff”), on behalf of Atwood Oceanics, Inc. (the “Company”), we submit the following responses to your letter dated April 26, 2017, relating to the Company’s Form 10-K for the year ended September 30, 2016. The captions and numbers set forth in this letter correspond to the captions and numbers included in the Staff’s letter of April 26, 2017. For your convenience, we are enclosing a copy of your April 26, 2017 letter.

Form 10-K for the fiscal year ended September 30, 2016

Financial Statements and Supplementary Data, page 45

Notes to Consolidated Financial Statements, page 52

Note 3 – Property and Equipment, page 57

Impairments

1. The first and second paragraphs on page two of the memorandum provided as part of your response to our comment letter dated March 9, 2017 provide a general description of factors you considered in projecting the timing and award of future contracts and in developing estimated operating day rates. Explain to us, in detail, how these factors were specifically considered to project the timing and award of future contracts and to develop estimated day rates for each individual rig. That is, for each individual rig, describe for us the specific factors that you considered to project contract timing and award and to develop estimated day rates. Your response should provide sufficient detail to clearly demonstrate how utilization and day rates were determined for each rig.

Response

Enclosed with this letter please find a memorandum (the “Supplemental Memorandum”) containing the Company’s response with respect to certain questions of the Staff set forth herein. Pursuant to Rule 418 under the Securities Act of 1933, as amended, and Rule 12b-4 under the Securities Exchange Act of 1934, as amended (collectively, the “Confidential Treatment Rules”), we are requesting that such supplemental information be returned to us or destroyed upon completion of your review and that, pending its return or destruction, it be withheld from release. We further request that the Freedom of Information Act officer of the Commission accord such supplemental information (but not, for the avoidance of doubt, the responses set forth in this letter) confidential treatment under the rules of the Commission.

2. Tell us the day rate specified in the recent contract for the Atwood Orca with Mubadala Petroleum for which operations are expected to commence in May 2017.

Response

Please see our response in the Supplemental Memorandum.

3. We note remarks attributed to you from your fourth quarter 2016 earnings call indicating that for you to have meaningful recovery, you need “to see north of $60 oil”. Please reconcile this statement with the timing of changes in utilization rates and day rates in the cash flow projections for your rigs as compared to the timing of when you expect oil prices to reach the $60 level, as described in the notes to the cash flow projections.

Response

The comment regarding management’s need “to see north of $60 oil” for meaningful recovery was made in the context of management’s best estimate as to when greater financial margins on drilling contracts may be realized within our industry (i.e., to have a “meaningful recovery”), rather than referring to the level that commodities prices needed to reach before contracting opportunities would resume for the offshore drilling industry. At the time this comment was made, Brent oil was trading at approximately $42 per barrel and management’s strategy for obtaining new work placed a higher priority on keeping individual drilling rigs operational and/or reactivating drilling rigs from idle status, as opposed to maximizing profitability. This strategy was intended to avoid the need to incur start-up costs after idling a rig, and address customers’ preference for operating drilling rigs over idled rigs. To this end, many of our recent discussions with smaller national oil company clients and potential other clients have focused on shorter term well workover and maintenance type drilling programs that were estimated to result in near breakeven margins.

Furthermore, it was the Company’s belief at such time that other larger integrated oil company clients might take advantage of lower operating day rates and enter into longer term drilling contracts to reduce drilling costs associated with the drilling programs. At such time, the Company believed that a market with Brent oil price higher than $60 per barrel would generate a significant increase in demand for new and larger scale offshore drilling programs initiated by our clients, and that increased demand, combined with the cost cutting efforts implemented throughout our organization would result in greater financial profitability to the Company (i.e., a “meaningful recovery”). Within our cash flow model, we have continued to project significantly reduced operating day rates, as compared to recent historical operating rates, through calendar years 2020/2021. Furthermore, subsequent to calendar years 2020/2021, the Company forecasted operating day rates to remain relatively flat, which illustrates what management believes to be a conservative assumption for future operating rates.

4. Information in your investor presentation dated March 28, 2017 indicates that you have a “young, high-specification fleet”. Explain to us how the utilization rates and day rates in your cash flow projections reflect the aging of your fleet over time.

Response

The Company’s cash flow model did not adjust either a drilling rig’s forecasted utilization rate or its forecasted operating rate specifically due to the age or relative technological advantage of the rig over its estimated economic useful life to the Company, primarily because (i) the cash flow model contains an inherently conservative bias due to being based on the Company’s then current five-year budget, (ii) utilization rates and day rates with respect to specific individual rigs have not historically been correlated with the rig’s increasing age and/or declining relative technological advantage; and (iii) our drilling rigs are expected, for the foreseeable future, to maintain their relative status as a young, high-specification fleet within the offshore drilling industry due to the lack of recent material research and development initiatives within the industry that might make existing technology obsolete.

Because our cash flow model is based on the Company’s five-year budget, the model reflects “bottom of the market” assumptions. These assumptions include day rates that are significantly below rates seen as recently as three years ago, and are kept relatively flat over the useful life of the rigs. Furthermore, as discussed above, due to the industry downturn, the Company’s recent strategy, which is reflected in the five-year budget, with respect to negotiating contracts in the near term has shifted from maximizing profitability with respect to each and every rig to prioritizing keeping certain individual drilling rigs operational, the result of which is that rigs are operating at day rates below optimal levels that would be typical in a traditional market with balanced supply and demand. As a result, outer years within the model have an inherent conservative bias which did not capture upside potential for having a young, high-specification fleet, and the Company believed it did not need to be further discount cash flows based on a theoretical decline in relative age technological advantage over time.

Furthermore, in a traditional market with balanced supply and demand, changes in utilization rates and day rates over time for a specific offshore drilling rig, although not perfectly correlated, are more closely tied to commodity prices, exploration and production capital expenditures, geographic region and supply of capable drilling rigs within the region of work, rather than to the age or technical specification of an individual drilling rig. The technology of a rig will often determine whether that rig can perform a type of work or within a particular region as a threshold matter. The type of work or region may generate higher day rates relative to other work that may be satisfied with lower specification rigs, but a rig that can meet the threshold specification will, over time, continue to retain the ability to obtain such work. For example, our two oldest semi-submersible drilling rigs, the Atwood Eagle and Atwood Falcon, which we sold for recycle purposes in May 2017 and April 2016, respectively, along with our oldest jackup drilling rig the Atwood Beacon, operated at high utilization and revenue efficiency rates at market competitive operating day rates over the last year of their most recent contracts, as illustrated by the following table:

Drilling Rig/ Classification	Service Period	Age of Rig at the End of Service Period		Average Utilization Rate			Average Revenue Efficiency Rate			Weighted Average Operating Rate		Peak Market Rate within Previous 5 Years (Approx.)
Atwood Eagle / Deepwater	12 months ended March 19, 2016		35		91	%		97	%	$	446,250	SE Asia Deepwater $490,000
Atwood Falcon / Deepwater	12 months ended March 3, 2016		34		97	%		98	%	$	430,750	SE Asia Deepwater $490,000
Atwood Beacon / Jackup	12 months ended August 9, 2016		14		96	%		96	%	$	127,250	World Wide Jackup $150,000

Finally, prior to the recent downturn, the offshore industry experienced a significant increase in the supply of drilling rigs as large numbers of newer, higher specification of rigs were constructed. However, in connection with the recent, sharp downturn in the industry, the construction of new build rigs and investment in research and development initiatives sharply declined as well. The Company does not believe that the market will return to constructing new rigs or making significant advancements in technology for the foreseeable future. As a result, the Company believes that its current fleet will maintain an advantage with respect to its age and relative technological capabilities for the foreseeable future.

5. We note the utilization rates assumed for your rigs for 2021 and later years. Tell us whether these are the utilization rates that you anticipate for all participants in the markets in which you will be participating, or if you believe you will achieve utilization rates that differ from other market participants. In either case, explain, in detail, the basis for your assumptions.

Response

The utilization rate assumptions used in our cash flow models represent management’s best estimate of utilization for our drilling rigs based on our operating history and our relative competitive advantage, rather than utilization for the entire offshore drilling industry. We believe that, as the industry emerges from the current down market, bifurcation within the market will become more pronounced, with younger, higher-specification rigs having a significant competitive advantage. As a result, when new contracting opportunities arise, clients will first seek to contract for young, high-specification drilling rigs such as ours. For all four of our drill ships and one of our two ultra-deepwater semi-submersibles, these new, high specification floaters are (or will soon be for the Atwood Condor) equipped with two blowout preventers (BOPs), which is very attractive to potential clients as this redundancy in equipment minimizes operational downtime and enhances safe drilling operations. Our fleet represents approximately 10% of drilling rigs in the industry with dual BOPs. The factors that are significant to our clients, we believe provide us with competitive advantages for the following reasons: (i) we operate a small fleet of high specification drilling rigs that averages less than six years in age (excluding the Atwood Eagle, which we sold for recycle purposes in May 2017), (ii) we are at or near the top of our industry in safety and reliability of drilling operations and (iii) our major drilling rig equipment (i.e., drilling systems, BOPs and riser joints) is common across our fleet which minimizes operating, training and repair/maintenance costs across our fleet. Furthermore, as discussed above, due to the sharp decline in construction of new build rigs and investment in research and development initiatives, the Company believes that its current fleet will maintain its advantage with respect to its age and relative technological capabilities for the foreseeable future. Given our estimate at September 30, 2016 of market recovery in the general offshore drilling industry near the end of 2018, along with what we believed to be specific competitive advantages over our competitors, we assumed a utilization rate that is higher than the expected industry average.

6. Information in your March 28, 2017 investor presentation suggests that, under certain circumstances, 90% floater utilization may be possible by the end of 2018. In view of this, explain to us the basis for the 2019 utilization rate you have assumed in your projections.

Response

In our March 28, 2017 investor presentation, we disclosed an illustrative estimate of floater asset recovery in the offshore drilling industry that we believe is possible near the end of calendar year 2018. Our analysis focused largely on the supply structure of floating rigs. An unprecedented number of floaters (drillships and semisubmersibles) have been removed from marketed supply since the offshore drilling industry downturn began in late 2014. Removal of floaters through scrapping or cold stacking decreased actively marketed rigs by 123 units from September 2014 through March 2017. The majority of this attrition was borne by vessels older than the fifth generation of floating rigs. Per our internal analysis, two areas of further significant floater rig attrition are likely to occur. First, floaters that have been idle and actively marketed for a significant period of time are less likely to return to work. Owners of such rigs have generally elected to cold stack the rigs to reduce costs after some period of idle time. Further, for rigs that have been inactive for lengthy durations, significant expenditures are required for reactivation. Such reactivation costs are greatest for older vessels due to hull repair for flag state classification, equipment repair and upgrading which are uneconomic in today’s market. Second, many multi-year contracts entered into at the height of the market are concluding (rolling over) through the end of 2018. Over a third of the vessels that roll over are fourth generation or older assets that will have large repair and maintenance projects and related costs. In the current market, clients can contract most rigs for a similar price, and we believe that operators will select the newest, most technically capable rigs due to their efficiencies that positively impact their project costs. In addition, due to our direct discussions with existing clients drilling program sanctioning activity, we believe there is potential for an uptick in floater tendering activity in the market. At a minimum, we believe that demand for floaters can maintain at March 2017 levels through the conclusion of 2018, and a contracted global fleet of 136 rigs juxtaposed with potential net rig attrition of 59 drilling rigs, results in industry-wide utilization improvement at the end of 2018 relative to March 2017.

As discussed above, we believe that, when new contracting opportunities arise as the industry recovers, clients will first seek to contract for young, high-specification drilling rigs that operate in a highly efficient and safe manner and at a competitive cost structure. Given our estimate at September 30, 2016 of market recovery in the general offshore drilling industry near the end of 2018, along with what we believed to be specific competitive advantages over our competitors, we assumed a utilization rate that is higher than the expected industry average.

7. Tell us whether, and, if so how, you have considered whether there is an estimated range for the amount of possible future cash flows associated with the future operations of your rigs and whether a probability-weighted approach, which considers the likelihood of the various possible outcomes, is appropriate. See FASB ASC 360-10-35-30.

Response

We considered the guidance in ASC 360-10-35-30, which states that a probability-weighted approach to forecasting may be useful in projecting future cash flows that are based on alternative courses of action. The method we have chosen incorporates the principles of this approach; however, it is modified slightly as compared to the examples referenced in this paragraph given the complex, highly subjective nature of forecasting and the many factors that impact operating rates, along with the fact that our assets are mobile. As noted in response to question #4 above, we believe, among other things, that commodity prices, exploration and production capital expenditures, geographic region and supply of

capable drilling rigs within the region of work have a significant impact on operating day rates. In addition, our drilling rigs may mobilize to different regions around the world (most recently the Atwood Condor mobilized from the U.S. Gulf of Mexico to Australia for a specified drilling program), which further complicates forecasting operating day rates for an individual drilling rig in future periods. Our forecasted operating day rates were developed based upon factors such as the operating region in which the drilling rig was expected to be marketed, discussions with current and potential clients and comparisons to competitor awards and third party industry analysis. The Company believes that the operating day rates presented in its cash flows model represent a conservative view of management’s best estimate of the operating day rates likely to be earned by each of our drilling rigs over their remaining economic useful lives. We believe this approach conforms to the principles outlined in ASC 360-10-35-30.

8. Note (e) to one of the cash flow projection for your jackup rigs explains that a periodic reduction in the utilization rate related to contract changes has been assumed for jackup rigs. However, the cash flow projections for other jack up rigs do not appear to reflect this periodic reduction in utilization rate. Please explain the reasons for this apparent inconsistency.

Response

Please see our response in the Supplemental Memorandum.

9. Explain to us where the projected utilization rates for your rigs reflect time necessary for any major repairs, maintenance, overhaul, surveys, upgrades or similar activities.

Response

Our projections for time necessary to complete repairs, maintenance, overhaul, surveys, upgrades or similar activities are reflected in the revenue efficiency rate assumptions included in our cash flow model for each of our drilling rigs, rather than the utilization rate assumption. Revenue efficiency is a measure of the rates earned under the terms of the contract relative to the operating day rate. In its most simple form, revenue efficiency of 50% assumes we operate in a manner such that we earn one half of the operating day rate over the contract term. We have implemented contractual and other process controls to maximize our revenue efficiency. First, in our standard contract for drilling services, we negotiate and agree with our client a number of days (or hours) for which we can perform survey activities (i.e., activities necessary to keep the drilling rig certified to work) and bill our client for this time. The rates for which we bill these activities may be the operating rate or a high percentage of the operating rate. As a recent example, we changed out a BOP on one of our drilling rigs and were able to complete the work without incurring any zero rate hours. In cases where we exceed the agreed upon hours for these types of activities, we may operate at zero rate. Second, our Operations and Maintenance departments, when possible, select the optimal times to perform normal repair and maintenance (R&M) activities. Less significant R&M work, may be completed while the drilling rig is performing drilling activities, while more significant R&M work may be completed during periods where the drilling rig is not performing drilling activities, which may include periods associated with between-well moves, client-initiated stand-by or waiting on weather events. For all four of our drill ships and one of our two ultra-deepwater semi-submersibles, these new, high specification floaters are (or will soon be for the Atwood Condor) equipped with two BOPs; this redundancy in equipment minimizes operational downtime for subsea maintenance. In summary, implementing these two strategies has led to average utilization and revenue efficiency rates fleet wide for the past five fiscal years of 99% and 95%, respectively.

10. Explain to us in greater detail the basis for your assumed changes over time in annual operating expenses. As part of your response, provide an analysis detailing the individual costs, e.g. wages and other compensation, repairs and maintenance, etc., included in this line item.

Response

Please see our response in the Supplemental Memorandum.

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Should you have any questions regarding this matter, please contact the undersigned at (281) 749-7800. Thank you for your assistance.

Very truly yours,
ATWOOD OCEANICS, INC.
By:	/s/ Mark W. Smith
	Name:	Mark W. Smith
	Title:	Senior Vice President, Chief Financial Officer