Edgar Filing: ATWOOD OCEANICS INC

Document



	UNITED STATES
	SECURITIES AND EXCHANGE COMMISSION
	WASHINGTON, DC 20549



(Mark One)		Form 10-Q



þ	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended December 31, 2016
	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		74-1611874
(State or Other Jurisdiction of Incorporation or Organization)		(IRS Employer Identification No.)

15011 Katy Freeway, Suite 800, Houston, Texas		77094
(Address of Principal Executive Offices including Zip Code)		(Zip Code)

Registrant’s Telephone Number, Including Area Code: (281) 749-7800



	N/A
	(Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report)

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 filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o

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

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.

As of February 1, 2017, there were 80,469,981 shares of common stock, $1.00 par value per share, outstanding.

ATWOOD OCEANICS, INC.

FORM 10-Q

FOR THE QUARTER ENDED DECEMBER 31, 2016

TABLE OF CONTENTS



Part I. Financial Information
Item 1.	Unaudited Condensed Consolidated Financial Statements	Page
a)	Unaudited Condensed Consolidated Statements of Operations for the Three Months ended December 31, 2016 and 2015	3
b)	Unaudited Condensed Consolidated Statements of Comprehensive Income for the Three Months ended December 31, 2016 and 2015	4
c)	Unaudited Condensed Consolidated Balance Sheets as of December 31, 2016 and September 30, 2016	5
d)	Unaudited Condensed Consolidated Statement of Changes in Shareholders' Equity for the Three Months Ended December 31, 2016	6
e)	Unaudited Condensed Consolidated Statements of Cash Flows for the Three Months Ended December 31, 2016 and 2015	7
f)	Notes to Unaudited Condensed Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	27
Item 4.	Controls and Procedures	27

Part II. Other Information
Item 1.	Legal Proceedings	28
Item 1A.	Risk Factors	28
Item 6.	Exhibits	29
Signatures		30

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ATWOOD OCEANICS, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)



	Three Months Ended December 31,
(In thousands, except per share amounts)	2016			2015
REVENUES:
Contract drilling	$	149,863		$	294,615
Revenues related to reimbursable expenses	7,693			13,204
Total revenues	157,556			307,819

COSTS AND EXPENSES:
Contract drilling	65,670			130,652
Reimbursable expenses	6,602			8,286
Depreciation	41,808			42,827
General and administrative	15,190			15,177
Asset impairment	—			64,724
(Gain) loss on sale of assets	(67		)	77
	129,203			261,743

OPERATING INCOME	28,353			46,076

OTHER INCOME (EXPENSE):
Interest expense, net of capitalized interest	(16,291		)	(13,761		)
Interest income	2			4
Other income	—			17,976
	(16,289		)	4,219

INCOME BEFORE INCOME TAXES	12,064			50,295
PROVISION FOR INCOME TAXES	2,393			11,214
NET INCOME	$	9,671		$	39,081

EARNINGS PER COMMON SHARE (NOTE 3):
Basic	$	0.15		$	0.60
Diluted	$	0.15		$	0.60
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (NOTE 3):
Basic	64,879			64,765
Diluted	65,171			64,921

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

ATWOOD OCEANICS, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(UNAUDITED)



	Three Months Ended December 31,
(In thousands)	2016		2015
Net income	$	9,671	$	39,081
Other comprehensive income:
Derivative financial instruments:
Unrealized holding gains/(losses)	739		(168		)
Loss reclassified to net income	445		694
Total other comprehensive income	1,184		526

Comprehensive income	$	10,855	$	39,607

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

ATWOOD OCEANICS, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS



(In thousands, except par value)	December 31, 2016			September 30, 2016
	(Unaudited)
ASSETS
Cash	$	160,110		$	145,427
Accounts receivable, net	95,464			113,091
Income tax receivable	6,471			6,095
Inventories of materials and supplies, net	110,462			109,925
Prepaid expenses, deferred costs and other current assets	15,745			18,504
Total current assets	388,252			393,042

Property and equipment, net	4,223,156			4,127,696

Other receivables	11,831			11,831
Deferred income taxes	165			165
Deferred costs and other assets	6,253			7,058
Total assets	$	4,629,657		$	4,539,792

LIABILITIES AND SHAREHOLDERS' EQUITY
Accounts payable	$	22,290		$	25,299
Accrued liabilities	9,076			7,868
Interest payable	14,896			7,096
Income tax payable	8,313			8,294
Deferred credits and other liabilities	285			799
Total current liabilities	54,860			49,356

Long-term debt	1,297,995			1,227,919
Deferred income taxes	1,403			1,202
Deferred credits	350			—
Other	30,613			30,929
Total long-term liabilities	1,330,361			1,260,050

Commitments and contingencies (Note 9)

Preferred stock, no par value, 1,000 shares authorized, none outstanding	—			—
Common stock, $1.00 par value, 180,000 shares authorized with 64,942 issued and outstanding as of December 31, 2016 and 180,000 shares authorized and 64,799 shares issued and outstanding as of September 30, 2016	64,942			64,799
Paid-in capital	241,558			237,542
Retained earnings	2,938,546			2,929,839
Accumulated other comprehensive loss	(610		)	(1,794		)
Total shareholders' equity	3,244,436			3,230,386
Total liabilities and shareholders' equity	$	4,629,657		$	4,539,792

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

ATWOOD OCEANICS, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY

(UNAUDITED)



	Common Stock			Paid-in			Retained			Accumulated Other Comprehensive			Total Stockholders’
(In thousands)	Shares	Amount		Capital			Earnings			Income (Loss)			Equity

September 30, 2016	64,799	$	64,799	$	237,542		$	2,929,839		$	(1,794	)	$	3,230,386

Net income	—	—		—			9,671			—			9,671
Cumulative effect of accounting change (Note 1)	—	—		964			(964		)	—			—
Other comprehensive income	—	—		—			—			1,184			1,184
Vesting of restricted stock and performance unit awards	143	143		(603		)	—			—			(460		)
Stock compensation expense	—	—		3,655			—			—			3,655
December 31, 2016	64,942	$	64,942	$	241,558		$	2,938,546		$	(610	)	$	3,244,436

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

ATWOOD OCEANICS, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)



	Three Months Ended December 31,
(In thousands)	2016			2015
Cash flows from operating activities:
Net income	$	9,671		$	39,081
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation	41,808			42,827
Amortization	922			1,250
Provision for doubtful accounts	2,369			757
Deferred income tax benefit	(185		)	(714		)
Share-based compensation expense	3,655			2,371
Asset impairment	—			64,724
(Gain) loss on sale of assets	(67		)	77
Changes in assets and liabilities:
Accounts receivable	15,258			60,883
Income tax receivable	(376		)	(829		)
Inventories of materials and supplies	(537		)	11,023
Prepaid expenses, deferred costs and other current assets	2,759			7,462
Deferred costs and other assets	(496		)	(1,050		)
Accounts payable	(1,396		)	(17,615		)
Accrued liabilities	9,191			8,570
Income tax payable	19			(642		)
Deferred credits and other liabilities	902			1,973
Net cash provided by operating activities	83,497			220,148

Cash flows from investing activities:
Capital expenditures	(138,814		)	(131,547		)
Net cash used in investing activities	(138,814		)	(131,547		)

Cash flows from financing activities:
Proceeds from issuance of long-term debt	125,000			45,000
Principal payments on long-term debt	(55,000		)	(115,000		)
Dividends paid	—			(16,316		)
Payments related to exercise of stock options	—			(599		)
Net cash provided by (used in) or financing activities	70,000			(86,915		)
Net increase in cash and cash equivalents	14,683			1,686
Cash and cash equivalents, at beginning of period	145,427			113,983
Cash and cash equivalents, at end of period	$	160,110		$	115,669

Non-cash activities:
(Decrease) increase in accounts payable related to capital expenditures	$	(1,613	)	$	10,530
Dividends payable	—			4,858

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

ATWOOD OCEANICS, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—UNAUDITED INTERIM INFORMATION

The accompanying unaudited condensed consolidated financial statements of Atwood Oceanics, Inc. and its subsidiaries as of December 31, 2016 and for the three months ended December 31, 2016 and 2015, have been prepared in accordance with accounting principles generally accepted in the United States for interim financial information. Unless otherwise indicated, references to “we”, “us”, “our” and the “Company” refer collectively to Atwood Oceanics, Inc. and subsidiaries. The year-end Consolidated Balance Sheet data was derived from the audited financial statements as of September 30, 2016. Although these financial statements and related information have been prepared without audit and certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America ("U.S.") have been condensed or omitted, we believe that the note disclosures are adequate to make the information not misleading. The interim financial results may not be indicative of results that could be expected for a full fiscal year. These unaudited condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and the related notes included in our Annual Report on Form 10-K for the year ended September 30, 2016. In our opinion, the unaudited interim financial statements reflect all adjustments considered necessary for a fair statement of our financial position, results of operations, changes in shareholders' equity, and cash flows for the periods presented.

Recently adopted accounting pronouncements

In August 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update (ASU) 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. The ASU is intended to reduce diversity in practice in how certain cash receipts and cash payments are presented in the statement of cash flows. The new guidance clarifies the classification of cash activity related to: (1) debt prepayment or debt extinguishment costs, (2) settlement of zero-coupon debt instruments, (3) contingent consideration payments made after a business combination, (4) proceeds from the settlement of insurance claims, (5) proceeds from the settlement of corporate and bank-owned life insurance policies, (6) distributions received from equity-method investments, and (7) beneficial interests in securitization transactions. This update is effective for annual and interim periods beginning after December 15, 2017. Effective October 1, 2016, we elected to early adopt ASU 2016-15. The adoption of ASU 2016-15 did not have an impact on our Unaudited Condensed Consolidated Statements of Cash Flows.

In March 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, as part of its simplification initiative. The ASU simplifies several aspects of the accounting for employee share-based payment transactions, including the accounting for income taxes, classification of excess tax benefits on the statements of cash flows, forfeitures, statutory tax withholding requirements, classification of awards as either equity or liabilities, and classification of employee taxes paid on the statements of cash flows when an employer withholds shares for tax-withholding purposes. The amendments in this update are effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The standard contains various amendments, each requiring a specific method of adoption, and designates whether each amendment should be adopted using a retrospective, modified retrospective, or prospective transition method. Effective October 1, 2016, we elected to early adopt the ASU. The amendments within the ASU relate to the timing of when excess tax benefits are recognized and the accounting for forfeitures. We adopted this ASU using a modified retrospective method. In accordance with this method, we have recorded a cumulative-effect adjustment in our Unaudited Condensed Consolidated Balance Sheet as of October 1, 2016, relating to the timing of recognition of excess tax benefits, of $6.6 million to the beginning Retained earnings that was offset by an equal increase to Deferred tax assets valuation allowance of the same amount resulting in no impact on Retained earnings. We also recorded a cumulative-effect adjustment in our Unaudited Condensed Consolidated Balance Sheet as of October 1, 2016, to reflect actual forfeitures versus the previously-estimated forfeiture rate, of $1.0 million reduction to the Retained earnings with an offset to Paid-in capital. The amendments within the ASU related to the recognition of excess tax benefits and tax shortfalls in the income statement and presentation of excess tax benefits on the statements of cash flows were adopted prospectively, with no impact to prior periods.

In November 2015, the FASB issued ASU 2015-17, Income Taxes (Topic 740): Amendments for the Balance Sheet Classification of Deferred Income Taxes. The amended guidance requires the classification of all deferred tax assets and liabilities as noncurrent on the balance sheet instead of separating deferred taxes into current and noncurrent amounts. Deferred tax assets and liabilities will continue to be offset and presented as a single amount under the amended guidance. The effective date for public business entities is for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Effective October 1, 2016, we elected to early adopt the ASU. The adoption of the ASU did not have an impact on our Condensed Consolidated Balance Sheet.

Recently issued accounting pronouncements

In October 2016, the FASB issued ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory. The ASU eliminates the exception to defer the tax effect for all intra-entity sales of assets other than inventory until the transferred asset is sold to a third party or otherwise recovered through use. As a result, a reporting entity would recognize the tax expense from the sale of the asset in the seller’s tax jurisdiction when the transfer occurs, even though the pre-tax effects of that transaction are eliminated in consolidation. Any deferred tax asset that arises in the buyer’s jurisdiction would also be recognized at the time of the transfer. This update is effective for annual and interim periods beginning after December 15, 2017. We are currently evaluating what impact the adoption of this guidance will have on our financial statements or disclosures in our financial statements.

In June, 2016, FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. The ASU introduces a new model for recognizing credit losses on financial instruments based on an estimate of current expected credit losses. The new model will apply to: (1) loans, accounts receivable, trade receivables, and other financial assets measured at amortized cost, (2) loan commitments and certain other off-balance sheet credit exposures, (3) debt securities and other financial assets measured at fair value through other comprehensive income/(loss), and (4) beneficial interests in securitized financial assets. This update is effective for annual and interim periods beginning after December 15, 2019. We are currently evaluating what impact the adoption of this guidance will have on our financial statements or disclosures in our financial statements.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification. The amendments require an entity to recognize lease assets and lease liabilities on the balance sheet and to disclose key qualitative and quantitative information about the entity's leasing arrangements. This update is effective for annual and interim periods beginning after December 15, 2018, with early adoption permitted. A modified retrospective approach is required. We are currently evaluating what impact the adoption of this guidance will have on our financial statements or disclosures in our financial statements.

In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements-Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. The new guidance requires management to assess a company’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. Disclosures are required when conditions give rise to substantial doubt. Substantial doubt is deemed to exist when it is probable that the company will be unable to meet its obligations within one year from the financial statement issuance date. The new guidance is effective for the annual period ending after December 15, 2016, and all annual and interim periods thereafter. We are currently evaluating what impact the adoption of this guidance will have on our financial statements or disclosures in our financial statements.

In May 2014, the FASB issued ASU 2014-09, Revenues from Contracts with Customers (Topic 606): A new guidance intended to change the criteria for recognition of revenue. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to clients in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The guidance is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. We have not yet adopted nor selected a transition method and are currently evaluating what impact the adoption of this guidance will have on our financial statements or disclosures in our financial statements.

NOTE 2—ACCOUNTS RECEIVABLE

We record accounts receivable at the amount we invoice our clients. Our clients are major international corporate entities and government organizations with stable payment experience. Historically, our uncollectible accounts receivable have been immaterial, and typically, we do not require collateral for our receivables. We provide an allowance for uncollectible accounts, as necessary, on a specific identification basis. Our allowance for doubtful accounts as of December 31, 2016 and September 30, 2016 was $2.3 million and $1.2 million, respectively. Our provision for doubtful accounts for the three months ended December 31, 2016 and 2015 was $2.4 million and $0.8 million, respectively. The provision for doubtful accounts is reported as a component of Contract drilling costs in our Condensed Consolidated Statements of Operations.

NOTE 3—EARNINGS PER COMMON SHARE

The computation of basic and diluted earnings per share for the three months ended December 31, 2016 and 2015 is as follows:



	Three Months Ended
(In thousands, except per share amounts)	Net Income		Shares	Per Share Amount
December 31, 2016
Basic earnings per share	$	9,671	64,879	$	0.15
Effect of dilutive securities:
Restricted stock and performance units	—		292	—
Diluted earnings per share	$	9,671	65,171	$	0.15
December 31, 2015
Basic earnings per share	$	39,081	64,765	0.60
Effect of dilutive securities:
Restricted stock and performance units	—		156	—
Diluted earnings per share	$	39,081	64,921	$	0.60

For the purpose of calculating diluted earnings per share for the three months ended December 31, 2016, there were approximately 3,401,718 anti-dilutive securities and for the three months ended December 31, 2015, there were approximately 1,584,000 anti-dilutive securities.

NOTE 4—PROPERTY AND EQUIPMENT

A summary of property and equipment by classification is as follows:



(In thousands)	December 31, 2016			September 30, 2016
Drilling vessels and equipment	$	3,909,804		$	3,898,686
Construction work in progress	981,351			857,572
Drill pipe	49,877			52,543
Office equipment and other	39,173			39,213
Total cost	4,980,205			4,848,014
Less: Accumulated depreciation	(757,049		)	(720,318		)
Property and equipment, net	$	4,223,156		$	4,127,696

Impairments

The Atwood Falcon completed the contract under which it was working in early March 2016. Based on the lack of contracting opportunities and the further deterioration of commodity prices, we determined that it was not likely that additional work would be obtained in the foreseeable future. Based on our analysis, we concluded that the Atwood Falcon and its materials and supplies were impaired as of December 31, 2015, and we wrote them down to their approximate salvage value. We recorded a non-cash impairment charge of approximately $64.7 million ($64.7 million net of tax, or $1.00 per diluted share), which is included in Asset Impairment on the Unaudited Condensed Consolidated Statement of Operations for the three months ended December 31, 2015. This impairment charge includes a write-down of property and equipment of $53.0 million and a write-down of our inventory of materials and supplies specific to the Atwood Falcon of $11.7 million. In April 2016, we completed the sale of the Atwood Falcon.

Other Income

During the three months ended December 31, 2015, we recognized approximately $18.0 million ($18.0 million, net of tax, or $0.28 per diluted share) of expected insurance recoveries related to cyclone damage to the Atwood Osprey. This amount is included in Other income on the Unaudited Condensed Consolidated Statement of Operations and was subsequently collected.

Construction Projects

As of December 31, 2016, we had expended approximately $970 million towards our two ultra-deepwater drillships under construction at the Daewoo Shipbuilding and Marine Engineering Co. ("DSME") shipyard in South Korea. Remaining expected capital expenditure for these two drillships under construction totaled approximately $300 million at December 31, 2016. On December 5, 2016, we entered into supplemental agreements (collectively, "Supplemental Agreement No. 5") to the construction

contracts with DSME which delay our requirements to take delivery of our two newbuild ultra-deepwater drillships, the Atwood Admiral and the Atwood Archer, by two years to September 30, 2019 and June 30, 2020, respectively. Supplemental Agreement No. 5 amends all material terms of the previous supplemental agreements. In consideration of Supplemental Agreement No. 5, we made a payment of $125 million for the Atwood Archer on December 13, 2016 and will make an additional interim payment of $15 million on the earlier of June 30, 2018 or the delivery date. With respect to the Atwood Admiral we will make a payment of $10 million on the earlier of September 30, 2017 or the delivery date. Remaining milestone payments, $83.9 million for the Atwood Admiral and $165 million for the Atwood Archer, have been extended until December 30, 2022. We have the ability to finance such amounts in the form of promissory notes to be entered into on the delivery dates for each vessel bearing interest at a rate of 5% per annum and to be secured by a mortgage on the respective drillship. We have the option to take earlier delivery of each vessel, upon 45 days' notice.

NOTE 5—DEBT

A summary of long-term debt is as follows:



(In thousands)	December 31, 2016			September 30, 2016
6.5% Senior Notes due 2020 ("Senior Notes") aggregate principal amount	$	448,650		$	448,650
Senior Notes unamortized premium	3,023			3,245
Senior Notes unamortized debt issuance costs	(3,678		)	(3,976		)
Total Senior Notes	447,995			447,919
Revolving Credit Facility ("Credit Facility")	850,000			780,000
Total long-term debt	$	1,297,995		$	1,227,919

Revolving Credit Facility

As of December 31, 2016, our Credit Facility had $1.395 billion of total commitments and $850 million of outstanding borrowings. As of December 31, 2016, we had approximately $545 million available for borrowings under the Credit Facility. Approximately $275 million of the commitments under the Credit Facility mature in May 2018 with the remaining $1.12 billion of the commitments maturing in May 2019. We were in compliance with all financial covenants under the Credit Facility as of December 31, 2016 and 2015, and we anticipate that we will continue to be in compliance for at least twelve months subsequent to the date our financial statements are issued.

The weighted-average effective interest rate on our long-term debt was approximately 4.9% per annum as of December 31, 2016. The effective rate was determined after giving consideration to the effect of our interest rate swaps accounted for as hedges and the amortization of our debt issuance costs and debt premiums. Interest capitalized for the three months ended December 31, 2016 and 2015 was approximately $5.4 million and $5.0 million, respectively.

NOTE 6—FAIR VALUE OF FINANCIAL INSTRUMENTS

We have certain assets and liabilities that are required to be measured and disclosed at fair value. Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date.

The fair value hierarchy prioritizes inputs to valuation techniques used to measure fair value into three levels. Priority is given to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Assets and liabilities measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values, stated below, takes into account the market for our financial assets and liabilities, the associated credit risk and other considerations.

We have classified and disclosed fair value measurements using the following levels of the fair value hierarchy:

Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.

Level 2: Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

Level 3: Measurement based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable for objective sources (i.e., supported by little or no market activity).

Fair value of Certain Assets and Liabilities

The fair value of cash, accounts receivable and accounts payable approximate fair value because of their short term maturities.

Fair Value of Financial Instruments

Independent third party services are used to determine the fair value of our financial instruments using quoted market prices and observable inputs. When independent third party services are used, we obtain an understanding of how the fair values are derived and selectively corroborate fair values by reviewing other readily available market based sources of information.

Long-term Debt— Our long-term debt consists of both our Senior Notes and our Credit Facility.

Senior Notes - The carrying value of our Senior Notes, net of unamortized premium, is $451.7 million ($448.7 million principal amount) while the fair value of our Senior Notes was $411.2 million at December 31, 2016. The fair value is determined by a market approach using quoted period-end bond prices. We have classified this as a Level 2 fair value measurement as valuation inputs for fair value measurements are quoted market prices at December 31, 2016 that can only be obtained from independent third party sources. The fair value amount has been calculated using these quoted prices. However, no assurance can be given that the fair value would be the amount realized in an active market exchange.

Credit Facility - Our Credit Facility is variable-rate and the carrying amounts of our variable-rate debt approximates fair value because such debt bears short-term, market-based interest rates. We have classified the fair value measurement of this instrument as Level 2 as valuation inputs for purposes of determining our fair value disclosure are readily available published Eurodollar rates.

Derivative financial instruments— Our derivative financial instruments consist of our interest rate swaps. We record our derivative contracts at fair value on our Unaudited Condensed Consolidated Balance Sheet. The fair values of our interest rate swaps are based upon valuations calculated by an independent third party. The derivatives were valued according to the "Market approach" where possible, and the "Income approach" otherwise. A third party independently valued each instrument using forward price data obtained from reputable data providers (e.g., Bloomberg and Reuters) and reviewed market activity and similarity of pricing terms to determine appropriate reliability level assertions for each instrument. The contribution of the credit valuation adjustment to total fair value is less than 1% for all derivatives and is therefore not significant. Based on valuation inputs for fair value measurement and independent review performed by third party consultants, we have classified our derivative contracts as Level 2 as they were valued based upon observable inputs from dealer markets.

The following table sets forth the estimated fair value of our derivative financial instruments, for which we elected hedge accounting, as of December 31, 2016 and September 30, 2016, by location and hedge type, which are measured and recorded at fair value on a recurring basis:



		December 31,			September 30,
(In thousands)	Balance Sheet Classification	2016			2016
Derivative assets designated as cash flow hedging instruments:
Long-term interest rate swap asset	Deferred costs and other assets	$	59		$	—
Derivative liabilities designated as cash flow hedging instruments:
Short-term interest rate swaps	Accrued liabilities	(669		)	(1,312		)
Long-term interest rate swaps	Other long-term liabilities	—			(482		)
Total derivative contracts, net		$	(610	)	$	(1,794	)

NOTE 7—SHARE-BASED COMPENSATION

A summary of our share-based compensation expense during the three months ended December 31, 2016 and 2015 is as follows:



	Three Months Ended December 31,
(In thousands, except average service periods)	2016		2015
Share-based compensation recognized	$	3,655	$	2,371
Unrecognized compensation cost, net of estimated forfeitures	26,666		25,940
Remaining weighted-average service period (years)	2.0		2.3

Restricted Stock Units

During the three months ended December 31, 2016, we granted to certain employees and our non-employee directors, restricted stock units that are subject to vesting conditions. The grant date fair value of these awards was based on the fair value of our common stock on the date of grant. A summary of our restricted stock activity for the three months ended December 31, 2016 is as follows:



	Number of Shares (000s)		Weighted Average Fair Value
Unvested as of October 1, 2016	1,515		$	21.96
Granted	1,099		7.83
Vested	(144	)	54.01
Forfeited	(36	)	27.72
Unvested as of December 31, 2016	2,434		13.73

Performance Units

During the three months ended December 31, 2016, we granted to certain employees share-based awards that are subject to market-based performance conditions ("Performance Units"). The grant date fair value of these performance units was determined through use of the Monte Carlo simulation method. A summary of Performance Units stock activity for the three months ended December 31, 2016 is as follows:



	Number of Shares (000s)		Weighted Average Fair Value
Unvested as of October 1, 2016	426		$	26.69
Granted	360		8.50
Vested	(47	)	53.55
Forfeited	(16	)	53.55
Unvested as of December 31, 2016	723		15.29

Stock Options

A summary of stock option activity for the three months ended December 31, 2016 is as follows:



	Number of Options (000s)		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (Years)	Aggregate Intrinsic Value (000s)
Outstanding as of October 1, 2016	617		$	35.47	3.4	$	(16,533	)
Granted	—		—		—	—
Exercised	—		—		—	—
Forfeited	—		—		—	—
Expired	(53	)	24.99		—	(633		)
Outstanding as of December 31, 2016	564		36.46		3.5	(13,159		)
Exercisable as of December 31, 2016	564		36.46		3.5	(13,159		)

NOTE 8— INCOME TAXES

We have historically calculated the provision for income taxes during interim reporting periods by applying an estimate of the annual effective tax rate for the full fiscal year to “ordinary” income or loss (pretax income or loss excluding unusual or infrequently occurring discrete items) for the reporting period. Beginning with the current reporting period, we have used a discrete effective tax rate method to calculate taxes for the three months ended December 31, 2016. We determined that since small changes in estimated “ordinary” income would result in significant changes in the estimated annual effective tax rate that the historical ("annualized") method would not provide a reliable estimate for the three months ended December 31, 2016. We anticipate that we will utilize the discrete effective tax rate method to calculate taxes for the remainder of the fiscal year.

Our estimated consolidated effective income tax rate for the three months ended December 31, 2016 was approximately 20%, as compared to 22% for the three months ended December 31, 2015. The effective tax rate for the three months ended December 31, 2016 was lower than the rate for the three months ended December 31, 2015, primarily due to a change in the geographical mix of income as well as the impact of an impairment charge taken against the Atwood Falcon during the three months ended December 31, 2015.

Our effective tax rate was lower than the U.S. statutory rate of 35% as a result of working in certain lower tax jurisdictions outside the United States. We record estimated accrued interest and penalties related to uncertain tax positions as income tax expense. As of December 31, 2016, we had approximately $15.7 million of reserves for uncertain tax positions, including estimated accrued interest and penalties of $3.5 million, which are included in Other long-term liabilities in the Unaudited Condensed Consolidated Balance Sheet. None of our reserves for uncertain tax positions relate to timing differences. All of the net uncertain tax liabilities would affect the effective tax rate if realized.

NOTE 9—COMMITMENTS AND CONTINGENCIES

Litigation

We are party to a number of lawsuits which are ordinary, routine litigation incidental to our business, the outcome of which is not expected to have, either individually or in the aggregate, a material adverse effect on our financial position, results of operations or cash flows.

NOTE 10—SUBSEQUENT EVENTS

Equity Offering

On January 13, 2017, we issued, in a public offering, 15,525,000 shares of common stock. The net proceeds from the offering, before deducting estimated offering expenses, were approximately $181.1 million. We expect to use the net proceeds for general corporate purposes, which may include the repayment of borrowings under the Credit Facility, the funding of future purchases of our Senior Notes, working capital and capital expenditures, and otherwise to enhance our liquidity.

Drilling Contract Amendments

fees covering the time periods for which the reduced day rate was previously invoiced. Effective February 1, 2017 and continuing until the contract end date of approximately November 12, 2017, the operating day rate is $595,000.

In February 2017, we amended our drilling services contract with Woodside Energy Ltd (“Woodside”) to substitute the Atwood Condor for the Atwood Osprey for the Greater Enfield campaign. The contract is expected to commence between December 2017 and March 2018 at an operating rate of $222,295 per day for approximately 550 days. Depending on the commencement of the contract, Woodside will reimburse us for the mobilization of the Atwood Condor to Australia in an amount of either $34.5 million or $36.5 million. In addition, we entered into a new agreement with Woodside to utilize the Atwood Osprey for an additional exploration well with an estimated duration of approximately 100 days. The contract for the exploration well is expected to commence between March 2018 and May 2018 at an operating rate of $190,000 per day with a priced option for an additional well. We will receive a mobilization fee of $1.0 million if the option is exercised and a payment of $2.0 million if the option is not exercised.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the accompanying unaudited condensed consolidated financial statements as of December 31, 2016 and for the three months ended December 31, 2016 and 2015 included in this report and with our Annual Report on Form 10-K for the fiscal year ended September 30, 2016. The following discussion and analysis contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of certain factors, including those set forth under “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the fiscal year ended September 30, 2016 and elsewhere in this report. See “Forward-Looking Statements” below.

OVERVIEW

Financial and operating results for the three months ended December 31, 2016, include:


•	Operating revenues totaling $158 million on 374 operating days for the three months ended December 31, 2016, as compared to operating revenues of $308 million on 830 operating days for the three months ended December 31, 2015;


•	Net income of $10 million for the three months ended December 31, 2016, as compared to net income of $39 million for the three months ended December 31, 2015;


•	Capital expenditures of $139 million for the three months ended December 31, 2016, as compared to capital expenditures of $132 million for the three months ended December 31, 2015; and


•	Increase in cash on hand of $15 million for the three months ended December 31, 2016 to $160 million.

MARKET OUTLOOK

Industry Conditions

The level of activity in the offshore drilling industry, which affects the sector's profitability, is cyclical and highly dependent on the offshore capital expenditure levels of exploration and production ("E&P") companies. In turn, E&P company offshore drilling expenditures are influenced by the current prices of oil and gas, expectations about future prices, company-specific cash flow levels, historical project returns and other capital allocation strategies (e.g., onshore versus offshore drilling).

The offshore drilling industry is in the midst of a very severe downturn that began in the second half of calendar year 2014. Since that time, the industry has experienced declining demand for drilling rigs that has been exacerbated by a sharp decline in oil prices. E&P companies generally reduced their offshore capital spending in 2015 and 2016 by canceling or deferring planned drilling programs, and this trend is expected to continue in the first half of 2017. Since declining to multi-year lows below $30 per barrel in early 2016, oil prices have recovered to approximately $55 per barrel in January 2017. However, we expect offshore rig demand to decline further into the first half of calendar year 2017 as offshore rigs complete existing contracts or have their contracts shortened or canceled at a faster rate than new drilling programs are initiated. Declines in offshore drilling demand and the associated reductions in rig utilization and day rates could materially and adversely affect our financial position, results of operation or cash flows. See "Our business depends on the level of activity in the oil and natural gas industry, which is significantly impacted by the volatility in oil and natural gas prices" under "Risk Factors" Item 1A of our Annual Report on Form 10-K for the fiscal year ended September 30, 2016.

Even as offshore rig demand declined from the peak levels in calendar year 2014, some drilling contractors continued to take delivery of new, more capable rigs that were ordered prior to the current industry downturn. However, over the past year drilling contractors have generally delayed further rig deliveries, especially for uncontracted rigs, through renegotiation of terms with the shipyards that are constructing these rigs. Due to the confluence of an oversupply of offshore rigs and declining rig demand, a lower percentage of marketed rigs are being re-contracted, and day rates and utilization have declined sharply across all offshore rig classes. While clients generally prefer newer, high specification rigs over older, less capable rigs, many newer floaters and jackups have been idled or cold-stacked as drilling demand has declined across all regions, water depths and rig classes. The bifurcation trend of higher utilization rates for newer rigs has been generally muted, and maintained more consistently for floaters than for jackups.

Due to the uncertain duration of the current industry downturn, a growing number of older, less capable rigs have been scrapped or announced for scrapping, and this trend accelerated throughout calendar year 2016. Even with the removal of approximately 43 ultra-deepwater and deepwater floaters and 46 jackups from the supply stack since the beginning of calendar year 2016, further declines in rig utilization and day rates are possible due to the persistent oversupply of offshore rigs relative to demand.

Consistent with our policy, we evaluate our drilling rigs and related equipment for impairment whenever events or changes in circumstances indicate the carrying value of these assets may exceed the estimated future net cash flows. Our evaluation, among other things, includes a review of external market factors and an assessment on the future marketability of a specific drilling unit. Further declines in offshore drilling demand, and/or a lack of improvement in drilling activity or day rates, may result in potential impairments to our drilling rigs and related equipment in the future. See "We may be required to record impairment charges with respect to our rigs" under "Risk Factors" Item 1A of our Annual Report on Form 10-K for the fiscal year ended September 30, 2016.

A current trend of some E&P companies to cancel, renegotiate, or repudiate existing drilling contracts has continued into 2017 as rig demand and market day rates have declined further. In January 2017, the client for the Atwood Achiever exercised its option provided as part of a “blend and extend” agreement negotiated with the client in October 2015 to revert the contract to the original operating day rate and original contract end date.

Some of our contracts with clients may be canceled at the option of the client upon payment of a termination fee which may not fully compensate us for the loss of the contract and may result in a rig being idled for an extended period of time. In addition, some of our clients could experience liquidity or solvency issues or could otherwise be unable or unwilling to perform under a contract, which could ultimately lead a client to enter bankruptcy or otherwise encourage a client to seek to repudiate, cancel or renegotiate a contract. Further deterioration in cash flow generation by E&P companies may accelerate these trends. If our clients seek to cancel or renegotiate our significant contracts and we are unable to negotiate favorable terms or secure new contracts on substantially similar terms, or at all, our revenues and profitability could be materially reduced. See "Our business may experience reduced profitability if our clients terminate or seek to renegotiate our drilling contracts" under "Risk Factors" Item 1A of our Annual Report on Form 10-K for the fiscal year ended September 30, 2016.

Ultra-deepwater and Deepwater Rig Markets

Both the ultra-deepwater and deepwater rig markets are experiencing declining demand, utilization and day rates. As of January 11, 2017, 90 ultra-deepwater rigs were under contract industry-wide (versus 125 on January 13, 2016) representing 70% utilization of a total of 129 actively marketed rigs. The number of marketed deepwater rigs under contract decreased to 22 (from 32 on January 13, 2016), which represents 59% utilization of the 37 active rigs. Declines in the percentage of marketed rigs under contract have been driven by reduced rig demand across all geographic regions coupled with an increase in marketed supply due to deliveries of newbuild rigs, primarily from South Korean and Singaporean shipyards.

As of January 11, 2017, 31 ultra-deepwater floaters were under construction with scheduled deliveries through April 2021, nine of which were contracted. However, this figure includes six floaters under long-term contracts with Petrobras, some or all of which may be delayed, repudiated, or canceled. In response to reduced rig demand and lack of suitable drilling programs, we and other drilling contractors have delayed delivery of uncontracted ultra-deepwater rigs under construction. Twenty-one ultra-deepwater rigs are scheduled for delivery during the remainder of calendar year 2017 and an additional ten units are scheduled for delivery in calendar year 2018 and beyond.

The number of idle offshore rigs being cold-stacked and scrapped has continued to increase due to the challenging market conditions. During calendar year 2016, 29 ultra-deepwater rigs and 14 deepwater rigs were announced for cold-stacking, retirement or scrapping and are no longer being actively marketed. We expect further attrition of marketed supply to continue into calendar year 2017 as there is expected to be limited re-contracting of floaters that complete their drilling programs, leading to a growing supply of idle rigs.

Our Ultra-deepwater Rigs and Deepwater Rigs

The Atwood Achiever, a dynamically positioned, ultra-deepwater drillship, is operating offshore Northwest Africa and as of December 31, 2016 was contracted through November 2018. In January 2017, our client exercised their option to revert the contract to its original day rate and original contract end date of November 2017. Exercising this option resulted in a one-time payment to us of $48.1 million.

The Atwood Advantage, a dynamically positioned, ultra-deepwater drillship, completed operations in the U.S. Gulf of Mexico in September 2016, after which it mobilized to the Mediterranean Sea to resume operations under its existing contract through August 2017.

The Atwood Condor, a dynamically positioned, ultra-deepwater semisubmersible, completed its contract in January 2017 and is idle in the U.S. Gulf of Mexico. In February 2017, we agreed with the client for the Atwood Osprey to transfer drilling services for a development drilling program in Australia scheduled to begin in January 2018 to the Atwood Condor. The Atwood Condor is scheduled to undergo maintenance and project preparation activities prior to commencing such program.

The Atwood Osprey, an ultra-deepwater semisubmersible is currently drilling in Australia and is under contract until March 2017 and is being actively marketed between March 2017 to May 2017, upon which time the rig will commence a one well contract estimated to last until September 2017. The rig also has a contract beginning in March 2018 for an expected duration of approximately 100 days.

The Atwood Eagle is currently idle in Singapore and is being actively marketed for a new drilling contract.

The Atwood Admiral and Atwood Archer are DP-3 dynamically-positioned, dual derrick, ultra-deepwater drillships rated to operate in water depths up to 12,000 feet and are currently under construction at the DSME shipyard in South Korea. These drillships will have enhanced technical capabilities, including two seven-ram BOPs, three 100-ton knuckle boom cranes, a 165-ton active heave “tree-running” knuckle boom crane and 200 person accommodations. Total cost, including project management, drilling and handling tools and spares, is approximately $635 million per drillship.

The Atwood Admiral and Atwood Archer were originally scheduled to be delivered in March 2015 and December 2015, respectively. Due to lack of suitable drilling programs, we have not yet secured the initial drilling contracts for these rigs. In December 2016, we entered into an amendment to delay the required delivery date of these two rigs to September 30, 2019 and June 30, 2020, respectively. We are unable to provide any assurance that we will obtain drilling contracts for these rigs prior to their delivery. See Note 4 to our Unaudited Condensed Consolidated Financial Statements in Item 1 of Part I of this Quarterly Report for further details regarding the remaining payments to be made with respect to these two drillships.

Jackup Rig Market

The jackup market is experiencing similar utilization, demand and day rate challenges as the floater market. Declining rig demand coupled with delivery of newbuild rigs, primarily from shipyards in China and Singapore, have negatively impacted the jackup rig supply and demand balance worldwide. In the current market downturn, all classes of jackup rigs have experienced lower day rates and utilization. The bifurcation trend that has historically favored utilization of new, higher specification jackups at the expense of older, lower specification jackups is generally not being maintained as clients have become much more price sensitive and are drilling fewer technically challenging wells. As of January 11, 2017, the percentage of marketed high specification jackup rigs (i.e., rigs equal to or greater than 350-foot water depth capability) under contract was approximately 62%, as compared to 65% for the remainder of the global jackup fleet.

We expect that the potential for further increases in global jackup supply due to delivery of high specification newbuild rigs may put additional pressure on jackup rig utilization and day rates. As of January 11, 2017, there were 103 newbuild jackup rigs under construction (from 125 on January 13, 2016), most of which are being constructed in China and many of which are owned by speculators or the constructing shipyards. Of the 78 jackup rigs scheduled for delivery in the remainder of calendar year 2017, only eight are contracted, while the remaining 25 rigs are scheduled for delivery primarily in calendar year 2018 and beyond. Similar to what has occurred with newbuild floaters, many of these scheduled jackup deliveries are expected to be delayed and/or canceled. Absent a strong recovery in high specification jackup rig demand and/or a significant reduction in jackup rig supply due to cold-stacking, scrapping or retirements, the marketed supply of jackups is likely to exceed client requirements well into calendar year 2017.

Through January 11, 2017, 20 high specification jackups and 26 standard jackups were cold-stacked, scrapped or retired from the beginning of calendar year 2016. This trend of marketed supply attrition is expected to continue into calendar year 2017 as older rigs face further declines in overall jackup demand and increased competition from newer, more capable rigs.

Our High Specification Jackup Rigs

The Atwood Mako and Atwood Manta, both 400-foot water depth Pacific Class jackup rigs, operated offshore Vietnam through September 2015 and offshore Thailand through October 2015, respectively. Both were idled in October 2015 after they completed their contracts and were unable to obtain follow-on work. The Atwood Beacon, a 400-foot water depth jackup, completed operations in the Mediterranean Sea in August 2016 and is currently idle in Malta. We are continuing to actively market these three high-specification jackup rigs while they are idle.

The Atwood Aurora, a 350-foot water depth jackup, completed operations offshore West Africa in September 2016 and is being towed to Malta where it will be idled. This rig is being actively marketed.

The Atwood Orca, a 400-foot water depth Pacific Class jackup completed operations in offshore Thailand in October 2016 and is currently idle in Singapore. In January 2017, the rig signed a one-year contract and will return to service in May 2017 offshore Thailand.

Contract Backlog

We maintain a backlog of commitments for contract drilling revenues. Our contract backlog as of December 31, 2016 was approximately $0.6 billion representing a 25% decrease compared to our contract backlog of $0.8 billion as of September 30, 2016 primarily due to realization of contract backlog. We calculate our contract backlog by multiplying the day rate under our drilling contracts by the number of days remaining under the contract, assuming full utilization. The calculation does not include any revenues related to mobilization, demobilization, contract preparation, and billing our clients for reimbursable items or bonuses. The amount of actual revenues earned and the actual periods during which revenues are earned will be different from the amounts disclosed in our backlog calculations due to a lack of predictability of various factors, including newbuild rig delivery dates, client elected standby periods unscheduled repairs, maintenance requirements, weather delays and other factors. Such factors may result in lower applicable day rates than the full contractual day rate and/or delays in receiving the full contractual operating rate. In addition, under certain circumstances, our clients may seek to terminate, repudiate or renegotiate our contracts, which could have the effect of reducing our contract backlog. See “Risks Related to our Business-Our business may experience reduced profitability if our clients terminate, repudiate, or renegotiate our drilling contracts” under Item 1A of our Annual Report on Form 10-K for the fiscal year ended September 30, 2016.

The following tables set forth the amount of our contract drilling revenue backlog and the percentage of available operating days committed for our fleet, excluding drilling units under construction, for the periods indicated as of December 31, 2016.



Contract Drilling Revenue Backlog	Remaining Fiscal 2017		Fiscal 2018		Fiscal 2019		Fiscal 2020		Fiscal 2021		Total
(In millions)
Ultra-deepwater	$	289	$	233	$	89	$	—	$	—	$	611
Deepwater	—		—		—		—		—		—
Jackups	—		—		—		—		—		—
Total	$	289	$	233	$	89	$	—	$	—	$	611



Percentage of Available Operating Days Committed	Remaining Fiscal 2017		Fiscal 2018		Fiscal 2019		Fiscal 2020		Fiscal 2021
Ultra-deepwater	59	%	44	%	27	%	—	%	—	%
Deepwater	—	%	—	%	—	%	—	%	—	%
Jackups	—	%	—	%	—	%	—	%	—	%
Total	24	%	17	%	11	%	—	%	—	%

Recent contract activity

In January 2017, the client for the Atwood Achiever exercised its option provided as part of the “blend and extend” agreement we entered into in October 2015 to revert the contract to the original operating day rate and original end date. Exercise of this option will result in a one-time payment to us of $48.1 million that includes the difference in day rates, taxes, and administrative fees covering the time periods for which the reduced day rate was previously invoiced. Effective February 1, 2017 and continuing until the contract end date of approximately November 12, 2017, the operating day rate is $595,000.

In January 2017, we signed a contract with Mubadala Petroleum to provide drilling services offshore Thailand for the Atwood Orca.

The following table set forth the amount of our contract drilling revenue backlog adjusted for recent contract activity since December 31, 2016.



Recent contract drilling revenue backlog	Remaining Fiscal 2017		Fiscal 2018			Fiscal 2019			Fiscal 2020		Fiscal 2021		Total
(In millions)
Backlog as of December 31, 2016	289		233			89			—		—		611
Revenues change	31		(120		)	(25		)	—		—		(114		)
Total Backlog as of February 2, 2017	$	320	$	113		$	64		$	—	$	—	$	497

RESULTS OF OPERATIONS

Revenues—Revenues for the three months ended December 31, 2016 decreased approximately $150 million, or 49%, as compared to the three months ended December 31, 2015. An analysis of revenues by rig category is as follows:



	REVENUES
	Three Months Ended December 31,
(In millions)	2016		2015		Variance
Ultra-Deepwater	$	148	$	182	$	(34	)
Deepwater	—		72		(72		)
Jackups	2		41		(39		)
Reimbursable	8		13		(5		)
	$	158	$	308	$	(150	)

Our ultra-deepwater fleet realized average revenues of $428,000 per day on 346 operating days for three months ended December 31, 2016, as compared to $523,000 per day on 348 operating days for three months ended December 31, 2015. The decrease in revenues for the ultra-deepwater fleet for three months ended December 31, 2016 was due to a lower contracted day rate for the Atwood Condor than the prior year. Additionally, the Atwood Advantage drilling contract was suspended to change drilling location from the U.S. Gulf of Mexico to the Mediterranean, and as a result the rig incurred 21 zero rate days to mobilize for operations in Israel.

Our deepwater fleet did not operate in the first quarter 2017, as compared to three months ended December 31, 2015, where operations were for 166 days at an average rate of $435,000 per day. The decrease in operating days and revenue is primarily due to the Atwood Falcon and Atwood Eagle completing their contracts in fiscal year 2016. The Atwood Falcon was idled and subsequently sold for recycling purposes, while the Atwood Eagle’s contract was suspended and remaining term transferred to the Atwood Osprey. The Atwood Eagle was subsequently idled.

Our jackup fleet realized average revenues of $79,000 per day on 28 operating days for three months ended December 31, 2016, as compared to $146,000 per day on 278 operating days for the three months ended December 31, 2015. The jackup fleet realized lower revenue and operating days for three months ended December 31, 2016, as compared to three months ended

December 31, 2015 primarily due to the completion of the drilling contracts of the fleet in prior fiscal years. The Atwood Orca operated for 28 days during the three months ended December 2016, and was subsequently idled.

Revenue related to reimbursable expenses is primarily driven by our clients’ requests for equipment, fuel, services and/or personnel that are not included in the contractual operating day rate. Thus, these revenues vary depending on the timing of the clients’ requests and the work performed. Additionally, as a result of a number of our rigs being idled, reimbursable revenue naturally declines while the rigs remain un-contracted. Changes in the amount of revenue related to reimbursable expenses generally do not have a material effect on our financial position, results of operations, or cash flows.

Drilling Costs—Drilling costs for the three months ended December 31, 2016 decreased approximately $67 million or 48%, as compared to the three months ended December 31, 2015. An analysis of contract drilling costs by rig category is as follows:



	CONTRACT DRILLING COSTS
	Three Months Ended December 31,
(In millions)	2016		2015		Variance
Ultra-Deepwater	$	50	$	61	$	(11	)
Deepwater	—		43		(43		)
Jackups	14		26		(12		)
Reimbursable	7		8		(1		)
Other	1		1		—
	$	72	$	139	$	(67	)

Ultra-deepwater drilling costs decreased for the three months ended December 31, 2016, as compared to the three months ended December 31, 2015. Average drilling costs per calendar day for our ultra-deepwater rigs decreased from approximately $167,000 for the three months ended December 31, 2015, to approximately $136,000 for the three months ended December 31, 2016. The drilling costs for our ultra-deepwater rigs were lower due to cost saving initiatives executed on payroll and maintenances costs that were implemented in the prior year.

Deepwater drilling costs decreased for the three months ended December 31, 2016, as compared to the three months ended December 31, 2015. Average drilling costs per calendar day for our deepwater rigs decreased from approximately $231,000 for the three months ended December 31, 2015, to approximately zero for the three months ended December 31, 2016. This decrease is due to contract completions on the Atwood Falcon and Atwood Eagle in fiscal year 2016. The Atwood Falcon was subsequently sold for recycling purposes in 2016, while the Atwood Eagle was idled after completion of its drilling contract.

Jackup drilling costs decreased for the three months ended December 31, 2016, as compared to the three months ended December 31, 2015, primarily due to the jackup fleet completing it's drilling contracts and being subsequently idled in prior years. The average drilling cost per calendar day decreased from approximately $78,000 for the three months ended December 31, 2015, to approximately $30,000 for the three months ended December 31, 2016.

Reimbursable costs are primarily driven by our clients’ requests for equipment, fuel, services and/or personnel that are not typically included in the contractual operating day rate. Thus, these costs vary depending on the timing of the clients’ requests and the work performed. Additionally, as a result of a number of our rigs being idled, reimbursable costs naturally decline while the rigs remain un-contracted. Changes in the amount of reimbursable costs generally do not have a material effect on our financial position, results of operations or cash flows.

Depreciation—For the three months ended December 31, 2016 total depreciation remained flat as compared to the three months ended December 31, 2015. An analysis of depreciation expense by rig category is as follows:



	DEPRECIATION EXPENSE
	Three Months Ended December 31,
(In millions)	2016		2015		Variance
Ultra-Deepwater	$	29	$	28	$	1
Deepwater	3		4		(1		)
Jackups	8		9		(1		)
Other	2		2		—
	$	42	$	43	$	(1	)

Asset Impairment— During the three months ended December 31, 2015, we recorded a non-cash impairment charge of approximately $64.7 million ($64.7 million, net of tax, or $1.00 per diluted share) to write the Atwood Falcon and its inventory of materials and supplies down to their approximate salvage value. See Note 4 to Condensed Consolidated Financial Statements in Item 1 of Part I of this Quarterly Report.

General and Administrative— For the three months ended December 31, 2016 and 2015, general and administrative expenses remained flat as compared to the prior year.

Interest Expense, net of capitalized interest— For the three months ended December 31, 2016, interest expense, net of capitalized interest, increased by approximately $2.5 million to $16.3 million, as compared to $13.8 million for the three months ended December 31, 2015, primarily due to a higher interest rate on our Credit Facility borrowings in the three months ended December 31, 2016.

Other Income— During the three months ended December 31, 2015, we recognized approximately $18.0 million ($18.0 million, net of tax, or $0.28 per diluted share) of insurance recoveries related to cyclone damage to the Atwood Osprey. This amount is included in Other income on the Unaudited Condensed Consolidated Statement of Operations and was subsequently collected.

Income Taxes— We have historically calculated the provision for income taxes during interim reporting periods by applying an estimate of the annual effective tax rate for the full fiscal year to “ordinary” income or loss (pretax income or loss excluding unusual or infrequently occurring discrete items) for the reporting period. Beginning with the current reporting period, we have used a discrete effective tax rate method to calculate taxes for the fiscal three month period ended December 31, 2016. We determined that since small changes in estimated “ordinary” income would result in significant changes in the estimated annual effective tax rate that the historical ("annualized") method would not provide a reliable estimate for the fiscal three month period ended December 31,2016. We anticipate that we will utilize the discrete effective tax rate method to calculate taxes for the remainder of the fiscal year.

LIQUIDITY AND CAPITAL RESOURCES

Sources of Liquidity

Our sources of available liquidity include existing cash balances on hand, cash flows from operations and borrowings under our Credit Facility. In addition, we may seek to access the debt and equity capital markets from time to time to raise additional capital, increase liquidity as necessary, fund additional purchases, exchange or redeem Senior Notes, repay amounts under our Credit Facility or otherwise refinance existing debt. Our ability to access the debt and equity capital markets depends on a number of factors, including our credit rating, industry conditions, general economic conditions, our revenue backlog, capital expenditure commitments, market conditions and market perceptions of us and our industry.

Our liquidity requirements include meeting ongoing working capital needs, repaying our outstanding indebtedness, and funding our capital expenditure projects. Our ability to meet these liquidity requirements will depend in large part on our future operating and financial performance.

Our cash flows fluctuate depending on a number of factors, including, among others, the number of our drilling units under contract, the day rates that we receive under those contracts, the efficiency with which we operate our drilling units, the timing of collections on outstanding accounts receivable, timing of payments to our vendors for operating costs, and capital expenditures. We continue to review and assess previously instituted company-wide cost savings measures, including the elimination of non-essential personnel and other operational measures, including delaying certain capital expenditure projects to ensure liquidity requirements reflect a level of expenditure consistent with the size of our anticipated fleet operating under client contracts over the next twelve months. These activities have had and continue to have a positive impact on our cash flow generation and overall liquidity. We believe that our cash on hand, cash flows from operations and available borrowings under our Credit Facility will provide sufficient liquidity over the next twelve months to fund our working capital needs, interest payments on our outstanding debt and other purposes.

As of December 31, 2016, we had $160 million in cash on hand. At any time, we may require a significant portion

of our cash on hand for working capital and other purposes. During the three months ended December 31, 2016, we relied principally on our cash flows from operations and cash on hand to meet liquidity needs and fund our cash requirements including our capital expenditures of $139 million. To date, general inflationary trends have not had a material effect on our operating revenues or expenses.

Cash Flows



	Three Months Ended December 31,
(In thousands)	2016			2015
Net cash provided by operating activities	$	83,497		$	220,148
Net cash used in investing activities	(138,814		)	(131,547		)
Net cash provided by (used in) or financing activities	70,000			(86,915		)

Operating Activities

Working capital decreased from $344 million as of September 30, 2016 to $333 million as of December 31, 2016. Net cash from operating activities for the three months ended December 31, 2016 was $83 million, as compared to $220 million for the three months ended December 31, 2015, primarily driven by reduced drilling activity.

Investing Activities

Capital Expenditures

Our investing activities are primarily related to capital expenditures for property and equipment. Our capital expenditures, including maintenance capital expenditures, for the three months ended December 31, 2016 and 2015 totaled $139 million and $132 million, respectively.

As of December 31, 2016, we had expended approximately $970 million towards our two ultra-deepwater drillships under construction at the DSME shipyard in South Korea.Remaining expected capital expenditure for these two drillships under construction totaled approximately $300 million at December 31, 2016. On December 5, 2016, we entered into supplemental agreements (collectively, "Supplemental Agreement No. 5") to the construction contracts with DSME which delay our requirements to take delivery of our two newbuild ultra-deepwater drillships, the Atwood Admiral and the Atwood Archer, by two years to September 30, 2019 and June 30, 2020, respectively. Supplemental Agreement No. 5 amends all material terms of the previous supplemental agreements. In consideration of Supplemental Agreement No. 5, we made a payment of $125 million for the Atwood Archer on December 13, 2016 and will make an additional interim payment of $15 million on the earlier of June 30, 2018 or the delivery date. With respect to the Atwood Admiral we will make a payment of $10 million on the earlier of September 30, 2017 or the delivery date. Remaining milestone payments, $83.9 million for the Atwood Admiral and $165 million for the Atwood Archer, have been extended until December 30, 2022. We have the ability to finance such amounts in the form of promissory notes

to be entered into on the delivery dates for each vessel bearing interest at a rate of 5% per annum and to be secured by a mortgage on the respective drillship. We have the option to take earlier delivery of each vessel, upon forty-five days' notice.

Financing Activities

Our financing activities primarily consist of borrowing and repayment of long-term and dividend payments. Proceeds received from borrowings from our Credit Facility totaled $125 million for the three months ended December 31, 2016. Repayments on our Credit Facility totaled $55 million for the three months ended December 31, 2016.

Dividends

We paid a dividend of $0.025 per share in October 2015 that was declared in August 2015. In February 2016, our board of directors eliminated the payment of a quarterly dividend in order to preserve liquidity. In March 2016, we amended the Credit Facility, which amendment, among other things, prohibits us from paying dividends during the remaining term of the Credit Facility. Future reinstatement of dividends would require the amendment or waiver of such provision. In addition, the declaration and amount of any future dividends would be at the discretion of our board of directors and would depend on our financial condition, results of operations, cash flows, prospects, industry conditions, capital requirements and other factors and restrictions our board of directors deems relevant. There can be no assurance that we will pay a dividend in the future.

Senior Notes (Due February 2020)

As of December 31, 2016, $448.7 million aggregate principal amount of our Senior Notes were outstanding. Our Senior Notes are unsecured obligations and are not guaranteed by any of our subsidiaries.

Pursuant to the terms of the indenture governing the Senior Notes, we have the option, on any one or more occasions, to redeem the Senior Notes in whole or in part at a redemption price of 101.625%, if redeemed prior to February 1, 2018, and 100.0% thereafter, in each case plus accrued and unpaid interest to the date of redemption. In addition, we may, from time to time, purchase Senior Notes in the open market, in privately negotiated transactions, through tender offers, exchange offers or otherwise. Any such future redemptions or purchases will depend on various factors existing at that time. There can be no assurance as to which of these alternatives (or combinations thereof), if any, we will pursue in the future.

Revolving Credit Facility

As of December 31, 2016, our Credit Facility had $1.395 billion of total commitments and $850 million of outstanding borrowings, providing approximately $545 million available for borrowings. Approximately $275 million of the commitments under the Credit Facility mature in May 2018 with the remaining $1.12 billion of the commitments maturing in May 2019. We were in compliance with all financial covenants under the Credit Facility as of December 31, 2016 and 2015, and we anticipate that we will continue to be in compliance for a least twelve months subsequent to the date our financial statements are issued.

The weighted-average effective interest rate on our long-term debt was approximately 4.9% per annum as of December 31, 2016. The effective rate was determined after giving consideration to the effect of our interest rate swaps accounted for as hedges and the amortization of debt issuance costs and our debt premiums. Interest capitalized for the three months ended December 31, 2016 and 2015 was approximately $5.4 million and $5.0 million, respectively.

The following summarizes our availability under our Credit Facility as of December 31, 2016 (in millions):



Commitment under Credit Facility	$	1,395
Borrowings under Credit Facility	850
Letters of Credit Outstanding	—
Availability	$	545

Letter of Credit Facility

In July 2015, we entered into a letter of credit facility with BNP Paribas (“BNP”), pursuant to which BNP may issue letters of credit up to an unlimited stated face amount of such letters of credit. BNP has no commitment under the facility to issue letters of credit, and the facility may be canceled by BNP at any time. The facility contains certain events of default, including but not limited to delinquent payments, bankruptcy filings, material adverse judgments, cross-defaults under other debt agreements, or a change of control. As of December 31, 2016, we have not requested any letters of credits under this facility.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements as that term is defined in Item 303(a)(4)(ii) of Regulation S-K.

Commitments and Contractual Obligations

For additional information about our commitments and contractual obligations as of December 31, 2016, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Commitments and Contractual Obligations” in our Annual Report on Form 10-K for the fiscal year ended September 30, 2016. As of December 31, 2016, other than payments made under our construction contracts, further postponement of the required delivery of the drilling units under construction, repayments under our Credit Facility, and the Supplemental Agreement No. 5 mentioned above, there were no material changes to this disclosure regarding our commitments and contractual obligations.

FORWARD-LOOKING STATEMENTS

Statements included in this Form 10-Q regarding future financial performance, capital sources and results of operations and other statements, other than statements of historical fact, that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, and Section 21E of the Securities Exchange Act of 1934. Such statements are those concerning strategic plans, expectations and objectives for future operations and performance. When used in this report, the words “believes,” “expects,” “anticipates,” “plans,” “intends,” “estimates,” “projects,” “could,” “should,” “may,” or similar expressions are intended to be among the statements that identify forward-looking statements.

Such statements are subject to numerous risks, uncertainties and assumptions that are beyond our ability to control, including, but not limited to:


•	prices of oil and natural gas and industry expectations about future prices;


•	market conditions and level of activity in the drilling industry and the global economy in general;


•	the level of capital expenditures by our clients;


•	the termination, renegotiation, or repudiation of contracts or payment delays by our clients;


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


•	the highly competitive and volatile nature of our business;


•	our ability to enter into, and the terms of, future drilling contracts, including contracts for our newbuild units, for rigs currently idled and for rigs whose contracts are expiring;


•	our ability to service our indebtedness and make payments on our rigs under construction;


•	our ability to access debt and equity capital markets, and the terms and prices that are available if we issue debt or equity securities;


•	the impact of governmental or industry regulation, both in the United States and internationally;


•	the risks of and disruptions to international operations, including political instability and the impact of terrorist acts, acts of piracy, embargoes, war or other military operations;


•	our ability to obtain and retain qualified personnel to operate our vessels;


•	unplanned downtime and repairs on our rigs;


•	timely access to spare parts, equipment and personnel to maintain and service our fleet;


•	client requirements for drilling capacity and client drilling plans;


•	the adequacy of sources of liquidity for us and for our clients;


•	changes in tax laws, treaties and regulations;


•	the risks involved in the construction, upgrade, and repair of our drilling units; and


•	such other risks discussed in Item 1A. “Risk Factors” of this Form 10-K and in our other reports filed with the Securities and Exchange Commission, or SEC.

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. Undue reliance should not be placed on these forward-looking statements, which are applicable only on the date hereof. We undertake no 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.

ITEM 3. QUANTITATIVE AND QUALITATIVE 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

The provisions of our Credit Facility provide for a variable interest rate cost on our $850 million outstanding as of December 31, 2016. However, we have employed an interest rate risk management strategy that utilizes derivative instruments with respect to $250 million of our debt outstanding as of December 31, 2016, in order to minimize unanticipated fluctuations in earnings and cash flows arising from changes in, and volatility of, interest rates. Effectively, $600 million of our variable long-term debt outstanding as of December 31, 2016, is subject to changes in interest rates. A change of 10% in the interest rate on the floating rate debt would not have a material effect on our annual earnings or cash flows.

Foreign Currency Risk

Our functional currency is the U.S. dollar. Certain of our subsidiaries have monetary assets and liabilities that are denominated in a currency other than our functional currency. The majority of our contracts are denominated in U.S. dollars, but occasionally all or 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 similar revenue in the local currency to the operating costs paid in the local currency such as local labor, shore base expenses, and local taxes, if any, in order to minimize foreign currency fluctuation impact.

From time to time, we enter into foreign currency forward exchange contracts to limit our exposure to fluctuations and volatility in currency exchange rates. We have outstanding foreign currency forward exchange contracts that were entered into to hedge a portion of our anticipated Eurodollar receipts associated with revenues earned. These forward contracts are designated as cash flow hedging instruments. Based on December 31, 2016 amounts, a decrease in the value of 10% in foreign currencies relative to the U.S. dollar would not have a material effect to our annual earnings or cash flows.

Market Risk

Our Senior Notes bear interest at a fixed interest rate. The fair value of our Senior Notes will fluctuate based on changes in prevailing market interest rates and market perceptions of our credit risk. The fair value of our Senior Notes was approximately $411.2 million as of December 31, 2016, compared to the principal amount of $448.7 million. If prevailing market interest rates had been 10% lower at December 31, 2016, the change in fair value of our Senior Notes would not have a material effect to our annual earnings or cash flows.

ITEM 4. 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 specified in the SEC’s rules, regulations and forms and have been accumulated and communicated to our management, including executive and financial officers, as appropriate, to allow timely decisions regarding required disclosures. 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)	Change in Internal Control over Financial Reporting

No change in our internal control over financial reporting occurred during the most recent fiscal quarter covered by this report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We have certain actions, claims and other matters pending as set forth in Note 9 to the Condensed Consolidated Financial Statements included in Item 1 of Part I of this Quarterly Report, which is incorporated by reference in response to this item. As of December 31, 2016, we were also involved in a number of lawsuits which have arisen in the ordinary course of business and for which we do not expect the liability, if any, resulting from these lawsuits to have a material adverse effect on our current consolidated financial position, results of operations or cash flows. We cannot predict with certainty the outcome or effect of any of these matters described above or any such other proceeding or threatened litigation or legal proceedings. There can be no assurance that our beliefs or expectations as to the outcome or effect of any lawsuit or other matters will prove correct and the eventual outcome of these matters could materially differ from management’s current estimates.

ITEM 1A. RISK FACTORS

For additional information about our risk factors, see Item 1A of our Annual Report on Form 10-K for the fiscal year ended September 30, 2016.

Table of Contents

ITEM 6. EXHIBITS


(a)	Exhibits





10.1†		Form of Notice of Performance Unit Grant (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed on November 22, 2016).

10.2†		Form of Notice of Restricted Stock Unit Award. (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed on November 22, 2016).

10.3†		Form of Notice of Cash-Settled Performance Unit Grant (incorporated by reference to Exhibit 10.3 to the Company's Current Report on Form 8-K filed on November 22, 2016).

10.4†		Form of Notice of Cash-Settled Restricted Stock Unit Award (incorporated by reference to Exhibit 10.4 to the Company's Current Report on Form 8-K filed on November 22, 2016).

10.5†		Form of Notice of Nonemployee Director Restricted Stock Unit Award (incorporated by reference to Exhibit 10.5 to the Company's Current Report on Form 8-K filed on November 22, 2016).

10.6		Supplemental Agreement No. 5 dated 5 December 2016 to the Drillship Contract dated 27 September 2012 by and between Alpha Admiral Company and Daewoo Shipbuilding & Marine Engineering Co., Ltd (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed on December 6, 2016).

10.7		Supplemental Agreement No. 5 dated 5 December 2016 to Drillship Contract dated 24 June 2013 by and between Alpha Archer Company and Daewoo Shipbuilding & Marine Engineering Co., Ltd. (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed on December 6, 2016).

*31.1		Certification of Chief Executive Officer.

*31.2		Certification of Chief Financial Officer.

**32.1		Certificate of Chief Executive Officer pursuant to Section 906 of Sarbanes – Oxley Act of 2002.

**32.2		Certificate of Chief Financial Officer pursuant to Section 906 of Sarbanes – Oxley Act of 2002.

*101		Interactive data files.

*		Filed herewith

**		Furnished herewith

†		Management contract or compensatory plan or arrangement

SIGNATURES

Pursuant to the requirements 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.
		(Registrant)

Date:	February 6, 2017	/S/ MARK W. SMITH
		Mark W. Smith
		Senior Vice President and Chief Financial Officer
		(Principal Financial and Accounting Officer)