Edgar Filing: PACIFIC DRILLING S.A.

Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 6-K

REPORT OF FOREIGN PRIVATE ISSUER

PURSUANT TO RULE 13a-16 OR 15d-16

UNDER THE SECURITIES EXCHANGE ACT OF 1934

For the quarter ended June 30, 2016

Commission File Number 001-35345

PACIFIC DRILLING S.A.

8-10, Avenue de la Gare

L-1610 Luxembourg

(Address of principal executive offices)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

Form 20-F x Form 40-F o

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1):

Yes o No x

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7):

Yes o No x

Indicate by check mark whether the registrant by furnishing the information contained in this Form, is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes o No x

If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b):

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PACIFIC DRILLING S.A.

TABLE OF CONTENTS



	Page
PART I — FINANCIAL INFORMATION	3
Item 1 — Financial Statements (Unaudited)	3
Unaudited Condensed Consolidated Financial Statements	3
Item 2 — Operating and Financial Review and Prospects	17
Item 3 — Quantitative and Qualitative Disclosure about Market Risk	30
PART II — OTHER INFORMATION	31
Item 1 — Legal Proceedings	31
Item 1A — Risk Factors	31
Item 2 — Unregistered Sales of Equity Securities and Use of Proceeds	31
Item 3 — Defaults Upon Senior Securities	31
Item 4 — Mine Safety Disclosures	31
Item 5 — Other Information	31
Item 6 — Exhibits	31

As used in this report on Form 6-K (this “Form 6-K”), unless the context otherwise requires, references to “Pacific Drilling,” the “Company,” “we,” “us,” “our” and words of similar import refer to Pacific Drilling S.A. and its subsidiaries. Unless otherwise indicated, all references to “U.S. $” and “$” in this report are to, and amounts are represented in, United States dollars.

The information and our unaudited condensed consolidated financial statements in this Form 6-K should be read in conjunction with our Annual Report on Form 20-F for the year ended December 31, 2015 (our “2015 Annual Report”) filed with the Securities and Exchange Commission (“SEC”) on March 1, 2016. We prepare our unaudited condensed consolidated financial statements in accordance with generally accepted accounting principles in the United States of America (“GAAP”).

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PART I — FINANCIAL INFORMATION

Item 1 — Financial Statements (Unaudited)

Unaudited Condensed Consolidated Financial Statements

PACIFIC DRILLING S.A. AND SUBSIDIARIES

Condensed Consolidated Statements of Operations

(in thousands, except per share information) (unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Revenues
Contract drilling	$	203,710		$	273,895		$	409,088		$	557,287
Costs and expenses
Operating expenses	(75,988		)	(110,388		)	(154,961		)	(228,057		)
General and administrative expenses	(14,195		)	(13,328		)	(29,321		)	(29,694		)
Depreciation expense	(68,213		)	(57,234		)	(136,289		)	(114,306		)
	(158,396		)	(180,950		)	(320,571		)	(372,057		)
Operating income	45,314			92,945			88,517			185,230
Other income (expense)
Interest expense	(46,116		)	(33,227		)	(91,609		)	(69,936		)
Gain on debt extinguishment	14,231			—			14,231			—
Other expense	(3,816		)	(343		)	(2,184		)	(2,394		)
Income before income taxes	9,613			59,375			8,955			112,900
Income tax expense	(1,379		)	(12,281		)	(3,232		)	(14,076		)
Net income	$	8,234		$	47,094		$	5,723		$	98,824
Earnings per common share, basic (Note 5)	$	0.39		$	2.23		$	0.27		$	4.66
Weighted-average number of common shares, basic (Note 5)	21,178			21,081			21,150			21,221
Earnings per common share, diluted (Note 5)	$	0.39		$	2.23		$	0.27		$	4.66
Weighted-average number of common shares, diluted (Note 5)	21,178			21,107			21,150			21,229

See accompanying notes to unaudited condensed consolidated financial statements.

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PACIFIC DRILLING S.A. AND SUBSIDIARIES

Condensed Consolidated Statements of Comprehensive Income

(in thousands) (unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
Net income	$	8,234		$	47,094		$	5,723		$	98,824
Other comprehensive income (loss):
Unrecognized loss on derivative instruments	(2,483		)	(623		)	(7,563		)	(11,333		)
Reclassification adjustment for loss on derivative instruments realized in net income (Note 7)	2,253			2,605			4,494			5,206
Reclassification adjustment for loss on derivative instruments realized in property and equipment (Note 7)	—			—			585			—
Total other comprehensive income (loss)	(230		)	1,982			(2,484		)	(6,127		)
Total comprehensive income	$	8,004		$	49,076		$	3,239		$	92,697

See accompanying notes to unaudited condensed consolidated financial statements.

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PACIFIC DRILLING S.A. AND SUBSIDIARIES

Condensed Consolidated Balance Sheets

(in thousands, except par value) (unaudited)



	June 30, 2016			December 31, 2015
Assets:
Cash and cash equivalents	$	371,084		$	116,033
Accounts receivable	138,182			168,050
Materials and supplies	95,245			98,243
Deferred costs, current	11,256			10,582
Prepaid expenses and other current assets	19,571			14,312
Total current assets	635,338			407,220
Property and equipment, net	5,035,427			5,143,556
Long-term receivable	202,575			202,575
Other assets	36,637			39,369
Total assets	$	5,909,977		$	5,792,720
Liabilities and shareholders’ equity:
Accounts payable	$	15,802		$	44,167
Accrued expenses	30,919			44,221
Long-term debt, current	74,364			76,793
Accrued interest	14,703			16,442
Derivative liabilities, current	7,606			7,483
Deferred revenue, current	42,497			49,227
Total current liabilities	185,891			238,333
Long-term debt, net of current maturities	2,946,189			2,768,877
Deferred revenue	42,053			60,639
Other long-term liabilities	36,962			32,816
Total long-term liabilities	3,025,204			2,862,332
Commitments and contingencies
Shareholders’ equity:
Common shares, $0.01 par value per share, 5,000,000 shares authorized, 22,551 and 23,277 shares issued and 21,182 and 21,121 shares outstanding as of June 30, 2016 and December 31, 2015, respectively	212			218
Additional paid-in capital	2,356,981			2,383,387
Treasury shares, at cost	—			(30,000		)
Accumulated other comprehensive loss	(25,974		)	(23,490		)
Retained earnings	367,663			361,940
Total shareholders’ equity	2,698,882			2,692,055
Total liabilities and shareholders’ equity	$	5,909,977		$	5,792,720

See accompanying notes to unaudited condensed consolidated financial statements.

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PACIFIC DRILLING S.A. AND SUBSIDIARIES

Condensed Consolidated Statements of Shareholders’ Equity

(in thousands) (unaudited)



	Common Shares				Additional Paid-In Capital			Treasury Shares					Accumulated Other Comprehensive Loss			Retained Earnings		Total Shareholders’ Equity
	Shares	Amount			Additional Paid-In Capital			Shares		Amount			Accumulated Other Comprehensive Loss			Retained Earnings		Total Shareholders’ Equity
Balance at December 31, 2015	21,121	$	218		$	2,383,387		2,156		$	(30,000	)	$	(23,490	)	$	361,940	$	2,692,055
Shares issued under share-based compensation plan	61	1			(88		)	(61	)	—			—			—		(87		)
Cancellation of treasury shares	—	(7		)	(29,993		)	(726	)	30,000			—			—		—
Share-based compensation	—	—			3,675			—		—			—			—		3,675
Other comprehensive loss	—	—			—			—		—			(2,484		)	—		(2,484		)
Net income	—	—			—			—		—			—			5,723		5,723
Balance at June 30, 2016	21,182	$	212		$	2,356,981		1,369		$	—		$	(25,974	)	$	367,663	$	2,698,882

See accompanying notes to unaudited condensed consolidated financial statements.

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PACIFIC DRILLING S.A. AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

(in thousands) (unaudited)



	Six Months Ended June 30,
	2016			2015
Cash flow from operating activities:
Net income	$	5,723		$	98,824
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation expense	136,289			114,306
Amortization of deferred revenue	(25,316		)	(44,172		)
Amortization of deferred costs	6,088			14,283
Amortization of deferred financing costs	7,266			5,199
Amortization of debt discount	645			452
Deferred income taxes	2,456			(1,493		)
Share-based compensation expense	3,675			5,824
Gain on debt extinguishment	(14,231		)	—
Changes in operating assets and liabilities:
Accounts receivable	29,868			41,531
Materials and supplies	2,998			(6,766		)
Prepaid expenses and other assets	(10,903		)	(2,787		)
Accounts payable and accrued expenses	(29,868		)	(18,927		)
Deferred revenue	—			2,288
Net cash provided by operating activities	114,690			208,562
Cash flow from investing activities:
Capital expenditures	(41,677		)	(102,116		)
Net cash used in investing activities	(41,677		)	(102,116		)
Cash flow from financing activities:
Net payments from shares issued under share-based compensation plan	(87		)	(419		)
Proceeds from long-term debt	235,000			265,000
Payments on long-term debt	(52,875		)	(411,293		)
Payments for financing costs	—			(500		)
Purchases of treasury shares	—			(21,760		)
Net cash provided by (used in) financing activities	182,038			(168,972		)
Net increase (decrease) in cash and cash equivalents	255,051			(62,526		)
Cash and cash equivalents, beginning of period	116,033			167,794
Cash and cash equivalents, end of period	$	371,084		$	105,268

See accompanying notes to unaudited condensed consolidated financial statements.

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PACIFIC DRILLING S.A. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements (Unaudited)

Note 1 — Nature of Business

Pacific Drilling S.A. and its subsidiaries (“Pacific Drilling,” the “Company,” “we,” “us” or “our”) is an international offshore drilling contractor committed to being the preferred provider of offshore drilling services to the oil and natural gas industry through the use of high-specification floating rigs. Our primary business is to contract our high-specification rigs to drill wells for our clients.

Note 2 — Significant Accounting Policies

Basis of Presentation — Our accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”) for interim financial information and Article 10 of Regulation S-X of the Securities and Exchange Commission. Pursuant to such rules and regulations, these financial statements do not include all disclosures required by GAAP for complete financial statements. Our unaudited condensed consolidated financial statements reflect all adjustments that are, in the opinion of management, necessary for a fair presentation of financial position, results of operations and cash flows for the presented interim periods. Such adjustments are considered to be of a normal recurring nature unless otherwise identified. Operating results for the three and six months ended June 30, 2016 are not necessarily indicative of the results that may be expected for the year ending December 31, 2016 or for any future period. The accompanying unaudited condensed consolidated financial statements and notes should be read in conjunction with the audited consolidated financial statements and notes of the Company for the year ended December 31, 2015.

Reverse Stock Split — On May 24, 2016, shareholders at our Extraordinary General Meeting approved a 1-for-10 reverse stock split of our common shares (the “Reverse Stock Split”). The Reverse Stock Split became effective and our common shares began trading on a split-adjusted basis as of the commencement of trading on May 25, 2016. On the effective date of the Reverse Stock Split, our shareholders received one new common share for every 10 common shares they owned. No fractional shares were issued in connection with the Reverse Stock Split; instead holders of fractional shares were paid out in cash for any fractional interests, which was not material in the aggregate. All share and per share information in the accompanying financial statements has been restated retroactively to reflect the Reverse Stock Split.

Principles of Consolidation — Our unaudited condensed consolidated financial statements include the accounts of Pacific Drilling S.A. and consolidated subsidiaries that we control by ownership of a majority voting interest and entities that meet the criteria for variable interest entities for which we are deemed to be the primary beneficiary for accounting purposes. We eliminate all intercompany transactions and balances in consolidation.

We are party to a Nigerian joint venture, Pacific International Drilling West Africa Limited (“PIDWAL”), with Derotech Offshore Services Limited (“Derotech”), a privately-held Nigerian registered limited liability company. Derotech owns 51% of PIDWAL and PIDWAL has a 50% ownership interest in two of our rig holding subsidiaries, Pacific Bora Ltd. and Pacific Scirocco Ltd. PIDWAL’s interest in the rig holding subsidiaries is held through a holding company of PIDWAL, Pacific Drillship Nigeria Limited (“PDNL”). Derotech will not accrue the economic benefits of its interest in PIDWAL unless and until it satisfies certain outstanding obligations to us and a certain pledge is cancelled by us. Likewise, PIDWAL will not accrue the economic benefits of its interest in PDNL unless and until it satisfies certain outstanding obligations to us and a certain pledge is cancelled by us. PIDWAL and PDNL are variable interest entities for which we are the primary beneficiary. Accordingly, we consolidate all interests of PIDWAL and PDNL and no portion of their operating results is allocated to the noncontrolling interest.

In addition to the joint venture agreement, we are a party to marketing and logistic services agreements with Derotech and an affiliated company of Derotech. During the three and six months ended June 30, 2016, we incurred fees of $2.4 million and $5.3 million, respectively, under such agreements. During the three and six months ended June 30, 2015, we incurred fees of $3.7 million and $6.9 million, respectively, under such agreements.

Recently Adopted Accounting Standards

Debt Issuance Costs — On April 7, 2015, Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-03, Interest - Imputation of Interest (Subtopic 835-30) - Simplifying the Presentation of Debt Issuance Costs, which requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a

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PACIFIC DRILLING S.A. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements (Unaudited) - Continued

direct deduction from the debt liability rather than as an asset. We adopted the standard effective January 1, 2016 on a retrospective basis, which resulted in the netting of our deferred financing costs against long-term debt balances on our consolidated balance sheets for the periods presented (see Note 4). Deferred financing costs related to our revolving credit facility were reclassified to prepaid expenses and other current assets, and other assets. The adoption had no impact on our operating results or cash flows for the current and prior periods.

Recently Issued Accounting Standards

Revenue Recognition — On May 28, 2014, FASB issued ASU 2014-09, Revenue from Contracts with Customers, which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. This standard will replace most existing revenue recognition guidance under GAAP when it becomes effective. The standard will be effective for annual periods and interim periods beginning after December 15, 2017. We plan to adopt the new standard on January 1, 2018. The standard permits the use of either the retrospective or cumulative effect transition method. We have not yet selected a transition method, and we are currently evaluating the effect the standard may have on our consolidated financial statements and related disclosures.

Deferred Taxes — On November 20, 2015, FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes, which requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. The new guidance, however, does not change the existing requirement that only permits offsetting within a tax jurisdiction. The standard will be effective for annual and interim periods beginning after December 15, 2016, and may be applied prospectively or retrospectively. We plan to adopt the standard prospectively effective January 1, 2017, and expect that it will result in the reclassification of our deferred tax balances from current to long-term on our consolidated balance sheets. As of June 30, 2016 and December 31, 2015, our current deferred tax assets and current deferred tax liabilities were $2.0 million and $2.1 million, respectively.

Leases — On February 25, 2016, FASB issued ASU 2016-02, Leases, which requires the balance sheet recognition of lease assets and lease liabilities by lessees for virtually all of their leases. Lessees and lessors will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. These practical expedients relate to the identification and classification of leases that commenced before the effective date, initial direct costs for leases that commenced before the effective date, and the ability to use hindsight in evaluating lessee options to extend or terminate a lease or to purchase the underlying asset. The standard will be effective for our annual and interim periods beginning January 1, 2019, although early adoption is permitted. We have not yet determined our implementation method upon adoption, and we are currently evaluating the effect the standard may have on our consolidated financial statements and related disclosures.

Share-based Payments — On March 30, 2016, FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which requires recognition of the income tax effects of equity awards in the income statement when the awards vest or are settled. The standard also allows employers to withhold shares upon settlement of an award for an amount up to the employees’ maximum individual tax rate in the relevant jurisdiction without resulting in liability classification of the award. The standard permits entities to make an accounting policy election for the impact of forfeitures on the recognition of expense for share-based payment awards. The standard will be effective for our annual and interim periods beginning January 1, 2017, although early adoption is permitted. We do not expect the adoption of the standard to have a material effect on our consolidated financial statements and related disclosures.

Measurement of Credit Losses on Financial Instruments — On June 16, 2016, FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326), which 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, and (4) beneficial interests in securitized financial assets. This update is effective for our annual and interim periods beginning after January 1, 2020. We are currently evaluating the effect the standard may have on our consolidated financial statements and related disclosures.

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PACIFIC DRILLING S.A. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements (Unaudited) - Continued

Note 3 — Property and Equipment

Property and equipment consists of the following:



	June 30, 2016			December 31, 2015
	(in thousands)
Drillships and related equipment	$	5,882,486		$	5,856,564
Other property and equipment	16,118			14,938
Property and equipment, cost	5,898,604			5,871,502
Accumulated depreciation	(863,177		)	(727,946		)
Property and equipment, net	$	5,035,427		$	5,143,556

Note 4 — Debt

Debt consists of the following:



	June 30, 2016			December 31, 2015
	(in thousands)
Due within one year:
2018 Senior Secured Term Loan B	$	7,500		$	7,500
Senior Secured Credit Facility	79,757			82,083
Less: unamortized deferred financing costs	(12,893		)	(12,790		)
Total current debt	74,364			76,793
Long-term debt:
2017 Senior Secured Notes	475,473			498,887
2018 Senior Secured Term Loan B	718,581			721,958
2013 Revolving Credit Facility	285,000			50,000
Senior Secured Credit Facility	737,448			775,000
2020 Senior Secured Notes	750,000			750,000
Less: unamortized deferred financing costs	(20,313		)	(26,968		)
Total long-term debt	2,946,189			2,768,877
Total debt	$	3,020,553		$	2,845,670

2017 Senior Secured Notes

In November 2012, Pacific Drilling V Limited (“PDV”), an indirect, wholly-owned subsidiary of the Company, and the Company, as guarantor, completed a private placement of $500.0 million in aggregate principal amount of 7.25% senior secured notes due 2017 (the “2017 Senior Secured Notes”). The 2017 Senior Secured Notes bear interest at 7.25% per annum, payable semiannually on June 1 and December 1, and mature on December 1, 2017.

The 2017 Senior Secured Notes are secured by a first-priority security interest (subject to certain exceptions) in the Pacific Khamsin, and substantially all of the other assets of PDV, including an assignment of earnings and insurance proceeds related to the Pacific Khamsin.

As of June 30, 2016, we have repurchased $23.7 million of our 2017 Senior Secured Notes for a purchase price of $9.1 million plus accrued interest. We recorded the resulting gain, net of the corresponding unamortized deferred financing costs and debt discount, of $14.2 million as a gain on debt extinguishment in our statements of operations.

Senior Secured Credit Facility Agreement

In February 2013, Pacific Sharav S.à r.l. and Pacific Drilling VII Limited (collectively, the “SSCF Borrowers”) and the Company, as guarantor, entered into a senior secured credit facility agreement, as amended and restated (the “SSCF”), to finance the construction, operation and other costs associated with the Pacific Sharav and the Pacific Meltem (the “SSCF Vessels”). The SSCF is primarily secured on a first priority basis by liens on the SSCF Vessels, and by an assignment of earnings and insurance proceeds relating thereto.

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PACIFIC DRILLING S.A. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements (Unaudited) - Continued

In 2015, we completed the final drawdown under this facility, resulting in a cumulative total drawdown of $985.0 million. We do not have any undrawn capacity on this facility as of June 30, 2016.

Following the final drawdown, the SSCF consisted of two principal tranches: (i) a Commercial Tranche of $492.5 million provided by a syndicate of commercial banks and (ii) a Garanti - Instituttet for Eksportkreditt (“GIEK”) Tranche of $492.5 million guaranteed by GIEK, comprised of two sub-tranches: (x) an Eksportkreditt Norge AS (“EKN”) sub-tranche of $246.3 million and (y) a bank sub-tranche of $246.3 million.

Borrowings under (A) the Commercial Tranche bear interest at London Interbank Offered Rate (“LIBOR”) plus a margin of 3.75%, (B) the EKN sub-tranche bear interest, at our option, at (i) LIBOR plus a margin of 1.5% (which margin may be reset on May 31, 2019) or (ii) at a Commercial Interest Reference Rate of 2.37%, and (C) the bank sub-tranche bear interest at LIBOR plus a margin of 1.5%. Borrowings under both sub-tranches are also subject to a guarantee fee of 2% per annum. Interest is payable quarterly. The SSCF requires semiannual amortization payments of $39.9 million. We have entered into interest rate swaps to hedge against fluctuations in LIBOR (see Note 7).

The Commercial Tranche matures on May 31, 2019. Loans made with respect to the Pacific Sharav under the GIEK Tranche mature on May 12, 2026. Loans made with respect to the Pacific Meltem under the GIEK Tranche mature on November 24, 2026. The GIEK Tranche contains a put option exercisable if the Commercial Tranche is not refinanced or renewed on or before February 28, 2019. If the GIEK Tranche put option is exercised, each SSCF Borrower must prepay, in full, the portion of all outstanding loans that relate to the GIEK Tranche, on or before May 31, 2019, without any premium, penalty or fees of any kind.

2020 Senior Secured Notes

On June 3, 2013, we completed a $750.0 million private placement of 5.375% senior secured notes due 2020 (the “2020 Senior Secured Notes”). The 2020 Senior Secured Notes bear interest at 5.375% per annum, payable semiannually on June 1 and December 1, and mature on June 1, 2020.

The 2020 Senior Secured Notes are guaranteed by each of our subsidiaries that own the Pacific Bora, the Pacific Mistral, the Pacific Scirocco and the Pacific Santa Ana (the “Shared Collateral Vessels”), each of our subsidiaries that own or previously owned equity or similar interests in a Shared Collateral Vessel-owning subsidiary, and certain other of our subsidiaries that are parties to charters in respect of the Shared Collateral Vessels, and will be guaranteed by certain other future subsidiaries. The indenture for the 2020 Senior Secured Notes allows for the issuance of up to $100.0 million of additional notes provided no default is continuing and we are otherwise in compliance with all applicable covenants.

The 2020 Senior Secured Notes are secured, on an equal and ratable, first priority basis, with the obligations under the Senior Secured Term Loan B (as defined below), the 2013 Revolving Credit Facility (as defined below) and certain future obligations (together with the 2020 Senior Secured Notes, the “Pari Passu Obligations”), subject to payment priorities in favor of lenders under the 2013 Revolving Credit Facility pursuant to the terms of an intercreditor agreement (the “Intercreditor Agreement”), by liens on the Shared Collateral Vessels, a pledge of the equity of the entities that own the Shared Collateral Vessels, assignments of earnings and insurance proceeds with respect to the Shared Collateral Vessels, and certain other assets of the subsidiary guarantors (collectively, the “Shared Collateral”).

2018 Senior Secured Institutional Term Loan – Term Loan B

On June 3, 2013, we entered into a $750.0 million senior secured institutional term loan maturing 2018 (the “Senior Secured Term Loan B”). The Senior Secured Term Loan B bears interest, at our election, at either (1) LIBOR, which will not be less than a floor of 1% plus a margin of 3.5% per annum, or (2) a rate of interest per annum equal to (i) the prime rate for such day, (ii) the sum of the federal funds rate plus 0.5% or (iii) 1% per annum above the one-month LIBOR, whichever is the highest rate in each case plus a margin of 2.5% per annum. Interest is payable quarterly. The Senior Secured Term Loan B requires quarterly amortization payments of $1.9 million and matures on June 3, 2018. We have entered into interest rate swaps to hedge against fluctuations in LIBOR (see Note 7).

The Senior Secured Term Loan B has an accordion feature that would permit additional loans to be extended so long as our total outstanding obligations in connection with the Senior Secured Term Loan B and the 2020 Senior Secured Notes do not exceed $1.7 billion.

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PACIFIC DRILLING S.A. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements (Unaudited) - Continued

The Senior Secured Term Loan B is secured by the Shared Collateral and subject to the terms and provisions of the Intercreditor Agreement.

2013 Revolving Credit Facility

On June 3, 2013, we entered into a $500.0 million senior secured revolving credit facility maturing 2018 (as amended, the “2013 Revolving Credit Facility”). The 2013 Revolving Credit Facility is secured by the Shared Collateral and subject to the provisions of the Intercreditor Agreement.

Borrowings under the 2013 Revolving Credit Facility bear interest, at our option, at either (1) LIBOR plus a margin ranging from 3.25% to 3.75% based on our leverage ratio, or (2) a rate of interest per annum equal to (i) the prime rate for such day, (ii) the sum of the federal funds rate plus 0.5% or (iii) 1% per annum above the one-month LIBOR, whichever is the highest rate in each case plus a margin ranging from 2.25% to 2.75% per annum based on our leverage ratio. Undrawn commitments accrue a fee ranging from 1.3% to 1.5% per annum based on our leverage ratio. Interest is payable quarterly.

The 2013 Revolving Credit Facility permits loans to be extended up to a maximum sublimit of $500.0 million and permits letters of credit to be issued up to a maximum sublimit of $300.0 million, subject to a $500.0 million overall facility limit. Outstanding but undrawn letters of credit accrue a fee at a rate equal to the margin on LIBOR loans minus 1%. The 2013 Revolving Credit Facility matures on June 3, 2018.

Covenants

As of June 30, 2016, we were in compliance with all of our debt covenants. However, market conditions continue to be challenging and it is possible we will need to seek amendments or waivers of such covenants during the next twelve months.

Note 5 — Earnings per Share

The following reflects the income and the share data used in the basic and diluted earnings per share computations:



	Three Months Ended June 30,				Six Months Ended June 30,
	2016		2015		2016		2015
	(in thousands, except per share information)
Numerator:
Net income, basic and diluted	$	8,234	$	47,094	$	5,723	$	98,824
Denominator:
Weighted-average number of common shares outstanding, basic	21,178		21,081		21,150		21,221
Effect of share-based compensation awards	—		26		—		8
Weighted-average number of common shares outstanding, diluted	21,178		21,107		21,150		21,229
Earnings per share:
Basic	$	0.39	$	2.23	$	0.27	$	4.66
Diluted	$	0.39	$	2.23	$	0.27	$	4.66

The following table presents the share effects of share-based compensation awards excluded from our computations of diluted earnings per share as their effect would have been anti-dilutive for the periods presented:



	Three Months Ended June 30,		Six Months Ended June 30,
	2016	2015	2016	2015
	(in thousands)		(in thousands)
Share-based compensation awards	1,225	959	1,225	977

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PACIFIC DRILLING S.A. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements (Unaudited) - Continued

Note 6 — Income Taxes

We recognize tax benefits from an uncertain tax position only if it is more likely than not that the position will be sustained upon examination by taxing authorities based on the technical merits of the position. The amount recognized is the largest benefit that we believe has greater than a 50% likelihood of being realized upon settlement. As of June 30, 2016 and December 31, 2015, we had $25.5 million and $24.9 million, respectively, of unrecognized tax benefits (excluding interest and penalties) which were included in other long-term liabilities on our consolidated balance sheet. The entire balance of unrecognized tax benefits as of June 30, 2016 would favorably impact our effective tax rate if recognized. Included on our balance sheet as of June 30, 2016 and December 31, 2015 were $3.4 million and $2.5 million, respectively, of interest and penalties related to unrecognized tax benefits.

Note 7 — Derivatives

We are currently exposed to market risk from changes in interest rates and foreign exchange rates. From time to time, we may enter into a variety of derivative financial instruments in connection with the management of our exposure to fluctuations in interest rates and foreign exchange rates. We do not enter into derivative transactions for speculative purposes; however, for accounting purposes, certain transactions may not meet the criteria for hedge accounting.

On May 30, 2013, we entered into an interest rate swap as a cash flow hedge against future fluctuations in LIBOR with an effective date of June 3, 2013. The interest rate swap has a notional value of $712.5 million, does not amortize and matures on December 3, 2017. On a quarterly basis, we pay a fixed rate of 1.56% and receive the maximum of 1% or three-month LIBOR.

On June 10, 2013, we entered into an interest rate swap as a cash flow hedge against future fluctuations in LIBOR with an effective date of July 1, 2014. The interest rate swap has a notional value of $400.0 million, does not amortize and matures on July 1, 2018. On a quarterly basis, we pay a fixed rate of 1.66% and receive three-month LIBOR.

On December 17, 2014, we entered into a series of foreign currency forward contracts as a cash flow hedge against future exchange rate fluctuations between the Euro and U.S. Dollar. We use the forward contracts to hedge Euro payments for forecasted capital expenditures. As of June 30, 2016, the remaining forward contracts have a notional value of €3.8 million and will be settled in December 2016. Upon settlement, we will pay U.S. Dollars and receive Euros at a forward rate of $1.27. As a result of partially settling the effective hedge for the six months ended June 30, 2016, we incurred a net cash outflow of $0.6 million and reclassified the amount from accumulated other comprehensive income to property and equipment.

The following table provides data about the fair values of derivatives that are designated as hedge instruments:



Derivatives Designated as Hedging Instruments	Balance Sheet Location	June 30, 2016			December 31, 2015
		(in thousands)
Short-term—Interest rate swaps	Derivative liabilities, current	$	(6,565	)	$	(5,899	)
Long-term—Interest rate swaps	Other long-term liabilities	(2,997		)	(238		)
Short-term—Foreign currency forward contracts	Derivative liabilities, current	(1,041		)	(1,584		)
Total		$	(10,603	)	$	(7,721	)

We have elected not to offset the fair value of derivatives subject to master netting agreements, but to report them on a gross basis on our condensed consolidated balance sheets.

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PACIFIC DRILLING S.A. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements (Unaudited) - Continued

The following table summarizes the cash flow hedge gains and losses for the three months ended June 30, 2016 and 2015:



Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized in Other Comprehensive Income (“OCI”) for the Three Months Ended June 30,					Loss Reclassified from Accumulated OCI into Income for the Three Months Ended June 30,				Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) for the Three Months Ended June 30,
Derivatives in Cash Flow Hedging Relationships	2016			2015		2016		2015		2016		2015
	(in thousands)
Interest rate swaps	$	(60	)	$	1,365	$	2,253	$	2,605	$	—	$	—
Foreign currency forward contracts	$	(170	)	$	617	$	—	$	—	$	—	$	—

The following table summarizes the cash flow hedge gains and losses for the six months ended June 30, 2016 and 2015:



Derivatives in Cash Flow Hedging Relationships	Gain (Loss) Recognized in Other Comprehensive Income (“OCI”) for the Six Months Ended June 30,						Loss Reclassified from Accumulated OCI into Income for the Six Months Ended June 30,				Gain (Loss) Recognized in Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) for the Six Months Ended June 30,
Derivatives in Cash Flow Hedging Relationships	2016			2015			2016		2015		2016		2015
	(in thousands)
Interest rate swaps	$	(3,028	)	$	(974	)	$	4,494	$	5,206	$	—	$	—
Foreign currency forward contracts	$	544		$	(5,153	)	$	—	$	—	$	—	$	—

As of June 30, 2016, the estimated amount of net losses associated with derivative instruments that would be reclassified from accumulated other comprehensive loss to earnings during the next twelve months was $7.4 million. During the three and six months ended June 30, 2016, we reclassified losses of $2.1 million and $4.1 million to interest expense and $0.2 million and $0.4 million to depreciation from accumulated other comprehensive loss, respectively. During the three and six months ended June 30, 2015, we reclassified losses of $2.4 million and $4.8 million to interest expense and $0.2 million and $0.4 million to depreciation from accumulated other comprehensive loss, respectively.

Note 8 — Fair Value Measurements

We estimated fair value by using appropriate valuation methodologies and information available to management as of June 30, 2016 and December 31, 2015. Considerable judgment is required in developing these estimates, and accordingly, estimated values may differ from actual results.

The estimated fair value of accounts receivable, accounts payable and accrued expenses approximated their carrying value due to their short-term nature. It is not practicable to estimate the fair value of our receivable from SHI (as defined in Note 9). It is also not practicable to estimate the fair value of our SSCF debt and 2013 Revolving Credit Facility. The following table presents the carrying value and estimated fair value of our other long-term debt instruments:



	June 30, 2016				December 31, 2015
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
	(in thousands)
2017 Senior Secured Notes	$	475,473	$	188,660	$	498,887	$	250,000
2018 Senior Secured Term Loan B	726,081		225,525		729,458		307,125
2020 Senior Secured Notes	750,000		250,673		750,000		322,500

We estimate the fair values of our variable-rate and fixed-rate debt using quoted market prices to the extent available and significant other observable inputs, which represent Level 2 fair value measurements.

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PACIFIC DRILLING S.A. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements (Unaudited) - Continued

The following table presents the carrying value and estimated fair value of our financial instruments recognized at fair value on a recurring basis:



	June 30, 2016
				Fair Value Measurements Using
	Carrying Value			Level 1	Level 2			Level 3
	(in thousands)
Liabilities:
Interest rate swaps	$	(9,562	)	—	$	(9,562	)	—
Foreign currency forward contracts	$	(1,041	)	—	$	(1,041	)	—

	December 31, 2015
				Fair Value Measurements Using
	Carrying Value			Level 1	Level 2			Level 3
	(in thousands)
Liabilities:
Interest rate swaps	$	(6,137	)	—	$	(6,137	)	—
Foreign currency forward contracts	$	(1,584	)	—	$	(1,584	)	—

We use an income approach to value assets and liabilities for outstanding interest rate swaps and foreign currency forward contracts. These contracts are valued using a discounted cash flow model that calculates the present value of future cash flows under the terms of the contracts using market information as of the reporting date, such as prevailing interest rates and forward rates. The determination of the fair values above incorporated various factors, including the impact of the counterparty’s non-performance risk with respect to our financial assets and our non-performance risk with respect to our financial liabilities.

See Note 7 for further discussion of our use of derivative instruments and their fair values.

Note 9 — Commitments and Contingencies

Commitments — As of June 30, 2016, we had no material commitments.

Our liquidity fluctuates depending on a number of factors, including, among others, our revenue efficiency and the timing of accounts receivable collection as well as payments for operating costs and debt repayments. Primary sources of funds for our short-term liquidity needs are expected to be our cash balances and cash flow generated from operating and financing activities. We believe our cash balances and cash flow generated from operating activities will provide sufficient liquidity over the next twelve months to fund our working capital needs and scheduled payments on our long-term debt.

Customs Bonds—As of June 30, 2016, we were contingently liable under certain customs bonds totaling approximately $53.7 million issued as security in the normal course of our business.

Contingencies — It is to be expected that we and our subsidiaries will routinely be involved in litigation and disputes arising in the ordinary course of our business.

On April 16, 2013, Transocean Offshore Deepwater Drilling, Inc. (“Transocean”) filed a complaint against us in the United States District Court for the Southern District of Texas alleging infringement of their dual activity patents, which was supplemented by an Amended Complaint filed on May 13, 2013. In its Amended Complaint, Transocean seeks relief in the form of a permanent injunction, compensatory damages, enhanced damages, court costs and fees. On May 31, 2013, we filed our Answer to the Amended Complaint and our Counterclaims seeking Declaratory Judgments that we do not infringe the asserted Transocean patents and that such patents are invalid and unenforceable. The trial was set for August 8, 2016; however, the Court has granted a stay of the litigation pending the resolution of three Inter Partes Reviews (“IPRs”) instituted by the U.S. Patent and Trademark Office (“PTO”) on March 28, 2016 with respect to the same three patents that are the subject of Transocean’s litigation against us. The PTO instituted the IPRs upon the petition of Seadrill Americas, Inc., Seadrill Gulf Operations Auriga, LLC, Seadrill Gulf Operations Vela, LLC and Seadrill Gulf Operations Neptune, LLC (collectively, “Seadrill”) based on a finding by the PTO that there is a reasonable likelihood that Seadrill will succeed in proving that at least

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PACIFIC DRILLING S.A. AND SUBSIDIARIES

Notes to Condensed Consolidated Financial Statements (Unaudited) - Continued

one of the asserted claims of each of the Transocean patents is invalid. Resolution of the IPRs is expected by the end of March 2017. We do not believe that the ultimate liability, if any, resulting from this litigation will have a material adverse effect on our financial position, results of operations or cash flows.

On October 29, 2015, we exercised our right to rescind the construction contract with Samsung Heavy Industries (“SHI”) for the drillship the Pacific Zonda (the “Construction Contract”) due to SHI’s failure to timely deliver the drillship in accordance with the contractual specifications. SHI rejected our rescission, and on November 25, 2015, formally commenced arbitration proceedings against us in London under the Arbitration Act 1996 before a tribunal of three arbitrators (as specified in the Construction Contract). SHI claims that we wrongfully rejected their tendered delivery of the drillship and seeks the final installment of the purchase price under the Construction Contract. On November 30, 2015, we made demand under the third party refund guarantee accompanying the Construction Contract for the amount of our advance payments made under the Construction Contract, plus interest. Any payment under the refund guarantee is suspended until an award under the arbitration is obtained. Pursuant to a mutually agreed scheduling order, SHI filed its claims submission on January 29, 2016. We responded with our defense and counterclaim on February 26, 2016 and, in addition to seeking repayment of our advance payments made under the Construction Contract, our counterclaim also seeks the return of our purchased equipment, or the value of such equipment, and damages for our wasted expenditures. SHI submitted their response to our defense and counterclaim on April 11, 2016, we filed our rejoinder on May 23, 2016 and SHI filed its sur-rejoinder on July 8, 2016. The pleadings are now complete and the disclosure phase of the arbitration proceeding has commenced. A hearing for the arbitration proceeding has been set for May 30, 2017. We do not believe that the ultimate outcome resulting from this arbitration will have a material adverse effect on our financial position, results of operations or cash flows.

Note 10 — Supplemental Cash Flow Information

Within our condensed consolidated statements of cash flows, capital expenditures represent expenditures for which cash payments were made during the period. These amounts exclude accrued capital expenditures, which are capital expenditures that were accrued but unpaid. During the six months ended June 30, 2016 and 2015, changes in accrued capital expenditures were $(11.9) million and $5.2 million, respectively.

During the six months ended June 30, 2016 and 2015, non-cash amortization of deferred financing costs and accretion of debt discount totaling $0 and $2.5 million were capitalized to property and equipment, respectively. Accordingly, these amounts are excluded from capital expenditures in our condensed consolidated statements of cash flows for the six months ended June 30, 2016 and 2015.

On May 2, 2016, shareholders at our Extraordinary General Meeting approved the cancellation of 7.3 million treasury shares (on a pre- Reverse Stock Split basis) that we repurchased under our share repurchase program. We accounted for this non-cash transaction by netting the treasury shares at total cost of $30.0 million against the statutory share capital of the cancelled shares and additional paid-in capital. Upon cancellation, the cancelled shares were returned to authorized but unissued shares.

Note 11 — Subsequent Events

In April 2016, Total notified us of its intent to terminate the drilling contract for the Pacific Scirocco for convenience. Throughout the second quarter, we continued to engage in discussions with Total regarding alternatives to early termination, during which we continued to earn 80% of the current dayrate. On July 22, 2016, Total rescinded the termination and notified us of its intent to restart operations at the full dayrate by September 15, 2016. We have further agreed to reduce the full dayrate to $455,000 from October 15, 2016 until the end of the contract term through January 19, 2017.

Following June 30, 2016, we pledged $82.0 million in cash and cash equivalents as collateral to the SSCF lenders to comply with the loan to value covenant, which requires semi-annual broker valuations of the vessels securing the SSCF to equal at least 125% of the outstanding SSCF balance as of the valuation date.

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Item 2 — Operating and Financial Review and Prospects

Overview

Our primary business is to contract our fleet of high-specification rigs to drill wells for our clients. We are focused on the high-specification segment of the floating rig market. The term “high-specification,” as used in the floating rig drilling industry to denote a particular segment of the market, can vary and continues to evolve with technological improvements. We generally consider high-specification requirements to include rigs capable of drilling in water depths of more than 7,500 feet or projects requiring advanced operating capabilities, such as high hook-loads (>1,000 tons), large accommodations (200+ beds), increased mud storage and pumping capacity, and high deck-load and space capabilities.

Our Fleet

The following table sets forth certain information regarding our fleet of high-specification drillships as of August 1, 2016:



Rig Name	Delivered	Water Depth (in feet)	Drilling Depth (in feet)	Customer
Pacific Bora^(a)	2010	10,000	37,500	Chevron
Pacific Scirocco	2011	12,000	40,000	Total
Pacific Santa Ana	2011	12,000	40,000	Chevron
Pacific Sharav	2014	12,000	40,000	Chevron
Pacific Mistral	2011	12,000	37,500	Available
Pacific Khamsin	2013	12,000	40,000	Available
Pacific Meltem	2014	12,000	40,000	Available

(a) Maximum water depth could be extended to up to 12,000 feet with drillship modifications.

Fleet Status

The status of our fleet as of August 1, 2016 is as follows:


•	The Pacific Bora entered service in Nigeria on August 26, 2011 under a three-year contract with a subsidiary of Chevron Corporation (“Chevron”), which has been extended through August 25, 2016.

•

The Pacific Scirocco entered service in Nigeria on December 31, 2011 under a contract with a subsidiary of Total S.A. (“Total”). In April 2016, Total notified us of its intent to terminate the drilling contract for the Pacific Scirocco for convenience. Throughout the second quarter, we continued to engage in discussions with Total regarding alternatives to early termination, during which we continued to earn 80% of the current dayrate. On July 22, 2016, Total rescinded the termination and notified us of its intent to restart operations at the full dayrate by September 15, 2016. We have further agreed to reduce the full dayrate to $455,000 from October 15, 2016 until the end of the contract term through January 19, 2017.


•	The Pacific Santa Ana entered service in the U.S. Gulf of Mexico on May 4, 2012 and is operating under a five-year contract with a subsidiary of Chevron through May 2017.


•	The Pacific Sharav entered service in the U.S. Gulf of Mexico on August 27, 2014 and is operating under a five-year contract with a subsidiary of Chevron through September 2019.


•	The Pacific Mistral completed its three-year contract with Petrobras in February 2015 and is currently idle in Aruba while actively seeking a contract.


•	The Pacific Khamsin completed its two-year contract with a subsidiary of Chevron in December 2015 and is currently in Cyprus while actively seeking a contract.


•	The Pacific Meltem is currently idle in Aruba while actively seeking a contract.

Significant Developments

See Note 11 to our unaudited condensed consolidated financial statements.

General Industry Trends and Outlook

Historically, operating results in the offshore contract drilling industry have been cyclical and directly related to the demand for and the available supply of drilling rigs, which are influenced by various factors. Since the latter half of 2014, oil prices have exhibited great volatility, declining significantly. Although dayrates and utilization for modern drillships have in the

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past been less sensitive to short-term oil price movements than those of older or less capable drilling rigs, the recent sustained declines in oil prices has rendered many deepwater projects less attractive to our customers and significantly impacted the number of projects available for modern drillships. The duration of weakness in oil prices remains uncertain.

Drilling Rig Supply

Across the industry, there have been no orders placed since April 2014 to build additional high-specification semi-submersibles or drillships, and within the last year, there have been several delays in delivery dates and canceled orders for new drillships. We estimate there are approximately 29 high-specification ultra-deepwater rigs delivered or scheduled for delivery from July 1, 2016 until the end of 2018, at least 18 of which have not yet been announced as being under contract for clients. Additionally, as a result of significantly reduced contracting activity, 30 to 35 rigs in the ultra-deepwater drilling industry sector have been removed from the actively marketed fleet through cold stacking or scrapping. This trend, along with additional delays in delivery dates and cancellations of existing orders for high-specification rigs, could continue as the offshore drilling market remains weak. The supply of high-specification units through the end of 2018 can be estimated as a range between 110 and 125. Beyond this time frame, the supply is uncertain and any projections have diminished predictive value.

Drilling Rig Demand

Demand for our drillships is a function of the worldwide levels of offshore exploration and development spending by oil and gas companies, which has decreased or been delayed significantly as result of the sustained decline in oil prices. The type of projects that modern drillships undertake are generally located in deeper water, in more remote locations, and are more capital intensive and longer lasting than those of older or less capable drilling rigs. The drilling programs of oil and gas companies are also affected by the global economic and political climate, access to quality drilling prospects, exploration success, perceived future availability and lead time requirements for drilling equipment, advances in drilling technology, and emphasis on deepwater and high-specification exploration and production versus other areas.

Overall, 2015 saw an extremely slow pace for high-specification contracting activity compared to prior years and this trend has continued in 2016. We expect contracting activity to be slow for the remainder of 2016.

Supply and Demand Balance

Since the start of the market downturn in 2014, capital expenditure budgets have significantly declined for many exploration and production companies, and we currently see utilization of the industry’s marketed modern drillships below 80%, which we expect to continue through 2016.

We estimate that through the end of 2016, approximately 30 to 35 high-specification rigs without currently confirmed client contracts will be available to commence operations. Additionally, multiple older, lower-specification ultra-deepwater and mid-water drillships and semisubmersibles have recently completed contracts without follow-on contracts. The imbalance of supply and demand has exerted considerable pressure on the market and resulted in very few signed drilling contracts and significantly lower dayrates than in past years for those rigs entering into new contracts. While recent scrapping and cold stacking of older assets have lowered the total rig supply, supply of drilling rigs continues to exceed demand. We believe that the industry will need to see a steady increase in oil prices and continue to remove additional rigs from supply in order to rebalance the global fleet.

For more information on this and other risks to our business and our industry, please read Item 3.D, “Risk Factors” in our 2015 Annual Report.

Contract Backlog

Our contract backlog includes firm commitments only, which are represented by signed drilling contracts. As of August 1, 2016 our contract backlog was approximately $927.3 million and was attributable to revenues we expect to generate on the Pacific Bora, the Pacific Santa Ana, the Pacific Sharav under drilling contracts with Chevron, and revenues we expect to generate on the Pacific Scirocco from Total. We calculate our contract backlog by multiplying the contractual dayrate by the minimum number of days committed under the contracts (excluding options to extend), assuming full utilization, and also including mobilization fees, upgrade reimbursements and other revenue sources, such as the standby rate during upgrades, as stipulated in the applicable contract.

The actual amounts of revenues earned and the actual periods during which revenues are earned may differ from the amounts and periods shown in the table below due to various factors. Our contracts customarily provide for termination at the election of the client with an “early termination payment” to be paid to us if a contract is terminated prior to the expiration of the fixed term. However, under certain limited circumstances, such as destruction of a drilling rig, our bankruptcy, sustained unacceptable performance by us or delivery of a rig beyond certain grace and/or liquidated damages periods, an early termination payment is not required to be paid. Accordingly, the actual amount of revenues earned may be substantially lower than the backlog reported.

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The firm commitments that comprise our $927.3 million contract backlog as of August 1, 2016, are as follows:

Rig

Contracted

Location

Client

Contract

Backlog^(a)

Contractual

Dayrate^(a)(b)

Average

Contract

Backlog

Revenue

Per

Day^(a)

Actual

Contract

Commencement

Expected

Contract

Duration

Pacific Bora

Nigeria

Chevron

14,520

586

602

August 26, 2011

5 years

Pacific Scirocco^(c)

Nigeria

Total

79,388

$ 489/455

^(c)

489/455

^(c)

December 31, 2011

5 years and 19 days

Pacific Santa Ana

U.S. Gulf of Mexico

Chevron

150,995

486

559

March 21, 2012

5 years and 38 days

Pacific Sharav

U.S. Gulf of Mexico

Chevron

682,358

556

609

August 27, 2014

5 years

__________________________


(a)	In thousands. Based on signed drilling contracts and signed commitments as further described above.


(b)	Based on current contractual dayrate amounts, subject to any applicable escalation provisions.


(c)	On July 22, 2016, Total rescinded the termination and notified us of its intent to restart operations at the full dayrate by September 15, 2016. We have further agreed to reduce the full dayrate to $455,000 from October 15, 2016 until the end of the contract term through January 19, 2017.

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Results of Operations

Three Months Ended June 30, 2016 Compared to Three Months Ended June 30, 2015

The following table provides a comparison of our condensed consolidated results of operations for the three months ended June 30, 2016 and 2015:



	Three Months Ended June 30,
	2016			2015			Change			% Change
	(in thousands, except percentages)
Revenues
Contract drilling	$	203,710		$	273,895		$	(70,185	)	26	%
Costs and expenses
Operating expenses	(75,988		)	(110,388		)	34,400			31	%
General and administrative expenses	(14,195		)	(13,328		)	(867		)	7	%
Depreciation expense	(68,213		)	(57,234		)	(10,979		)	19	%
	(158,396		)	(180,950		)	22,554			12	%
Operating income	45,314			92,945			(47,631		)	51	%
Other income (expense)
Interest expense	(46,116		)	(33,227		)	(12,889		)	39	%
Gain on debt extinguishment	14,231			—			14,231			100	%
Other expense	(3,816		)	(343		)	(3,473		)	1,013	%
Income before income taxes	9,613			59,375			(49,762		)	84	%
Income tax expense	(1,379		)	(12,281		)	10,902			89	%
Net income	$	8,234		$	47,094		$	(38,860	)	83	%

Revenues. The decrease in revenues for the three months ended June 30, 2016, as compared to the three months ended June 30, 2015, resulted primarily from the Pacific Khamsin being idle during the period and the Pacific Scirocco being on an 80% standby rate starting in May 2016. The decrease was partially offset by higher revenue efficiency for our operating rigs.

During the three months ended June 30, 2016, our operating fleet of drillships achieved an average revenue efficiency of 99.0% compared to 95.5% for the three months ended June 30, 2015. Revenue efficiency is defined as the actual contractual dayrate revenue (excluding mobilization fees, upgrade reimbursements and other revenue sources) divided by the maximum amount of total contractual dayrate revenue that could have been earned during such period.

Contract drilling revenue for the three months ended June 30, 2016 and 2015 also included amortization of deferred revenue of $12.7 million and $21.5 million and reimbursable revenues of $5.9 million and $9.7 million, respectively. The decrease in the amortization of deferred revenue was primarily due to completion of the primary contract term for the Pacific Khamsin in December 2015. Reimbursable revenues represent the gross amount earned related to costs for the purchase of supplies, equipment, personnel services and other services provided at the request of our clients that are beyond the initial scope of the drilling contract. The decrease in reimbursable revenues was related to corresponding decreases in reimbursable costs incurred.

Operating expenses. The following table summarizes operating expenses:



	Three Months Ended June 30,
	2016		2015
	(in thousands)
Direct rig related operating expenses, net	$	59,540	$	87,570
Reimbursable costs	6,129		9,086
Shore-based and other support costs	7,066		7,933
Amortization of deferred costs	3,253		5,799
Total	$	75,988	$	110,388

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The decrease in direct rig related operating expenses for the three months ended June 30, 2016, as compared to the three months ended June 30, 2015, resulted from lower operating costs for the Pacific Khamsin subsequent to completion of its contract and cost saving measures implemented for both operating and idle drillships.

Reimbursable costs are not included under the scope of the drilling contract’s initial dayrate, but are subject to reimbursement from our clients. Reimbursable costs can be highly variable between quarters. Because the reimbursement of these costs by our clients is recorded as additional revenue, they do not generally negatively affect our margins.

The decrease in amortization of deferred costs was primarily due to completion of the primary contract term for the Pacific Khamsin in December 2015.

Direct rig related operating expenses and shore-based and other support costs divided by the number of operating and idle rig days were as follows:



	Three Months Ended June 30,
	2016		2015
	(in thousands, amounts per rig per day)
Direct rig related operating expenses, net	$	93.5	$	160.4
Shore-based and other support costs	11.1		14.5
Total	$	104.6	$	174.9

The decrease in direct rig related operating expenses per operating and idle rig per day for the three months ended June 30, 2016, as compared to the same period in 2015, was attributable to lower costs on idle drillships during the second quarter of 2016, and fleet wide cost saving measures implemented.

The decrease in shore-based and other support costs per operating and idle rig per day for the three months ended June 30, 2016, as compared to the same period in 2015, was due to reductions in Brazil and Nigeria office costs, and the implementation of cost saving measures.

General and administrative expenses. General and administrative expenses for the three months ended June 30, 2016 were in line with the three months ended June 30, 2015, resulting from our cost saving measures, partially offset by higher legal costs associated with the patent litigation and arbitration proceeding.

Depreciation expense. The increase in depreciation expense for the three months ended June 30, 2016, as compared to the same period in 2015, related to depreciation expense incurred on the Pacific Meltem, after being placed into service on August 25, 2015.

Interest expense. The following table summarizes interest expense:



	Three Months Ended June 30,
	2016			2015
	(in thousands)
Interest	$	(44,062	)	$	(43,757	)
Realized losses on interest rate swaps	(2,054		)	(2,406		)
Capitalized interest	—			12,936
Interest expense	$	(46,116	)	$	(33,227	)

The increase in interest expense for the three months ended June 30, 2016, as compared to the same period of 2015, was due to a reduction in capitalized interest on the Pacific Meltem and the Pacific Zonda.

Gain on debt extinguishment. During the three months ended June 30, 2016, we repurchased $23.7 million of our 2017 Senior Secured Notes for a purchase price of $9.1 million plus accrued interest. We recorded the resulting gain, net of the corresponding unamortized deferred financing costs and debt discount, of $14.2 million as a gain on debt extinguishment in our statements of operations.

Other expense. The change in other expense primarily related to the currency exchange loss due to the devaluation of Nigerian Naira against the U.S. Dollar in the second quarter of 2016.

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Income taxes. In accordance with GAAP, we estimate the full-year effective tax rate from continuing operations and apply this rate to our year-to-date income from continuing operations. In addition, we separately calculate the tax impact of unusual or infrequent items, if any. The tax impacts of such unusual or infrequent items are treated discretely in the quarter in which they occur. During the three months ended June 30, 2016 and 2015, our effective tax rate was 14.3% and 20.7%, respectively. Excluding discrete items, our effective tax rate for the three months ended June 30, 2016 was (19.9)%.

The relationship between our provision for or benefit from income taxes and our pre-tax book income can vary significantly from period to period considering, among other factors, (a) the overall level of pre-tax book income, (b) changes in the blend of income that is taxed based on gross revenues or at high effective tax rates versus pre-tax book income or at low effective tax rates and (c) our rig operating structures. Consequently, our income tax expense does not change proportionally with our pre-tax book income. Significant decreases in our pre-tax book income typically result in higher effective tax rates, while significant increases in pre-tax book income can lead to lower effective tax rates, subject to the other factors impacting income tax expense noted above. Additionally, pre-tax book losses typically result in negative effective tax rates. The decrease in our effective tax rate for the three months ended June 30, 2016 to negative levels, as compared to the three months ended June 30, 2015 was the result of our idle drillships, which are generating losses for which no tax benefit is expected.

Six Months Ended June 30, 2016 Compared to Six Months Ended June 30, 2015

The following table provides a comparison of our condensed consolidated results of operations for the six months ended June 30, 2016 and 2015:



	Six Months Ended June 30,
	2016			2015			Change			% Change
	(in thousands, except percentages)
Revenues
Contract drilling	$	409,088		$	557,287		$	(148,199	)	27	%
Costs and expenses
Operating expenses	(154,961		)	(228,057		)	73,096			32	%
General and administrative expenses	(29,321		)	(29,694		)	373			1	%
Depreciation expense	(136,289		)	(114,306		)	(21,983		)	19	%
	(320,571		)	(372,057		)	51,486			14	%
Operating income	88,517			185,230			(96,713		)	52	%
Other income (expense)
Interest expense	(91,609		)	(69,936		)	(21,673		)	31	%
Gain on debt extinguishment	14,231			—			14,231			100	%
Other expense	(2,184		)	(2,394		)	210			9	%
Income before income taxes	8,955			112,900			(103,945		)	92	%
Income tax expense	(3,232		)	(14,076		)	10,844			77	%
Net income	$	5,723		$	98,824		$	(93,101	)	94	%

Revenues. The decrease in revenues for the six months ended June 30, 2016, as compared to the six months ended June 30, 2015, resulted primarily from the Pacific Khamsin and the Pacific Mistral being idle during the period, and the Pacific Scirocco being on an 80% standby rate starting in May 2016. The decrease was partially offset by higher revenue efficiency for our operating rigs.

During the six months ended June 30, 2016, our operating fleet of drillships increased average revenue efficiency to 98.4%, as compared to 95.3% during the six months ended June 30, 2015.

Contract drilling revenue for the six months ended June 30, 2016 and 2015 also included amortization of deferred revenue of $25.3 million and $44.2 million and reimbursable revenues of $11.3 million and $15.6 million, respectively. The decrease in the amortization of deferred revenue was primarily due to completion of the primary contract term for the Pacific Mistral in February 2015 and the Pacific Khamsin in December 2015.

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Operating expenses. The following table summarizes operating expenses:



	Six Months Ended June 30,
	2016		2015
	(in thousands)
Direct rig related operating expenses, net	$	122,575	$	181,640
Reimbursable costs	11,152		14,893
Shore-based and other support costs	15,146		17,241
Amortization of deferred costs	6,088		14,283
Total	$	154,961	$	228,057

The decrease in direct rig related operating expenses for the six months ended June 30, 2016, as compared to the six months ended June 30, 2015, resulted from lower operating costs for the Pacific Mistral and the Pacific Khamsin subsequent to completion of their respective contracts and cost saving measures implemented for both operating and idle drillships.

The decrease in amortization of deferred costs was primarily due to completion of the primary contract term for the Pacific Mistral in February 2015 and for the Pacific Khamsin in December 2015.

Direct rig related operating expenses and shore-based and other support costs divided by the number of operating and idle rig days were as follows:



	Six Months Ended June 30,
	2016		2015
	(in thousands, amounts per rig per day)
Direct rig related operating expenses, net	$	96.2	$	167.3
Shore-based and other support costs	11.9		15.9
Total	$	108.1	$	183.2

The decrease in direct rig related operating expenses per operating and idle rig per day for the six months ended June 30, 2016, as compared to the same period in 2015, was attributable to lower costs on idle drillships and fleet wide cost saving measures implemented.

The decrease in shore-based and other support costs per operating and idle rig per day for the six months ended June 30, 2016, as compared to the same period in 2015, was due to reductions in Brazil and Nigeria office costs, and the implementation of cost saving measures.

General and administrative expenses. The decrease in general and administrative expenses for the six months ended June 30, 2016, as compared to the six months ended June 30, 2015, resulted from cost saving measures partially offset by higher legal costs associated with the patent litigation and arbitration proceeding.

Depreciation expense. The increase in depreciation expense for the six months ended June 30, 2016, as compared to the same period in 2015, related to depreciation expense incurred on the Pacific Meltem, after being placed into service on August 25, 2015.

Interest expense. The following table summarizes interest expense:



	Six Months Ended June 30,
	2016			2015
	(in thousands)
Interest	$	(87,513	)	$	(91,040	)
Realized losses on interest rate swaps	(4,096		)	(4,808		)
Capitalized interest	—			25,912
Interest expense	$	(91,609	)	$	(69,936	)

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The increase in interest expense for the six months ended June 30, 2016, as compared to the same period in 2015, was primarily due to a reduction in capitalized interest on the Pacific Meltem and the Pacific Zonda.

Gain on debt extinguishment. During the six months ended June 30, 2016, we repurchased $23.7 million of our 2017 Senior Secured Notes for a purchase price of $9.1 million plus accrued interest. We recorded the resulting gain, net of the corresponding unamortized deferred financing costs and debt discount, of $14.2 million as a gain on debt extinguishment in our statements of operations.

Other expense. The decrease in other expense primarily related to the currency exchange loss due to the devaluation of Nigerian Naira against the U.S. Dollar in the second quarter of 2016.

Income taxes. In accordance with GAAP, we estimate the full-year effective tax rate from continuing operations and apply this rate to our year-to-date income from continuing operations. In addition, we separately calculate the tax impact of unusual or infrequent items, if any. For the six months ended June 30, 2016 and 2015, our effective tax rate was 36.1% and 12.5%, respectively. Excluding discrete items, the effective tax rate for the six months ended June 30, 2016 was (21.7)%.

The relationship between our provision for or benefit from income taxes and our pre-tax book income can vary significantly from period to period considering, among other factors, (a) the overall level of pre-tax book income, (b) changes in the blend of income that is taxed based on gross revenues versus pre-tax book income, and (c) our rig operating structures. Consequently, our income tax expense does not necessarily change proportionally with our pre-tax book income. Significant decreases in our pre-tax book income typically result in higher effective tax rates, while significant increases in pre-tax book income can lead to lower effective tax rates, subject to the other factors impacting income tax expense noted above. Additionally, pre-tax book losses typically result in negative effective tax rates. The decrease in our effective tax rate for the six months ended June 30, 2016 to negative levels, as compared to the six months ended June 30, 2015 was the result of our idle drillships, which are generating losses for which no tax benefit is expected.

Liquidity and Capital Resources

Liquidity

As of June 30, 2016, we had $371.1 million of cash and cash equivalents, of which $82.0 million was pledged to the lenders under the SSCF as cash collateral in August 2016. In addition, we currently have in place a $500.0 million revolving credit facility that matures in June 2018. As of June 30, 2016, we had drawn $285.0 million under this facility. Our ability to draw further indebtedness under this facility is limited by a secured debt incurrence covenant contained in our 2017 senior secured notes.

Our liquidity requirements include meeting ongoing working capital needs, repaying our outstanding indebtedness and maintaining adequate credit facilities or cash balances to compensate for the effects of fluctuations in operating cash flows. Our liquidity fluctuates depending on a number of factors, including, among others, our revenue efficiency and the timing of accounts receivable collection as well as payments for operating costs and debt repayments. Our ability to meet these liquidity requirements will depend in large part on our future operating and financial performance as well as market conditions, including our ability to enter into new drilling contracts for our vessels.

Primary sources of funds for our short-term liquidity needs are expected to be our cash balances and cash flow generated from operating and financing activities. We believe our cash balances and cash flow generated from operating activities will provide sufficient liquidity over the next twelve months to fund our working capital needs and scheduled payments on our long-term debt. We expect to fund our long-term liquidity requirements through operating and financing activities.

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Sources and Uses of Cash

The following table provides a comparison of our net cash provided by operating activities for the six months ended June 30, 2016 and 2015:



	Six Months Ended June 30,
	2016			2015			Change
	(in thousands)
Cash flow from operating activities:
Net income	$	5,723		$	98,824		$	(93,101	)
Depreciation expense	136,289			114,306			21,983
Amortization of deferred revenue	(25,316		)	(44,172		)	18,856
Amortization of deferred costs	6,088			14,283			(8,195		)
Amortization of deferred financing costs	7,266			5,199			2,067
Amortization of debt discount	645			452			193
Deferred income taxes	2,456			(1,493		)	3,949
Share-based compensation expense	3,675			5,824			(2,149		)
Gain on debt extinguishment	(14,231		)	—			(14,231		)
Changes in operating assets and liabilities, net	(7,905		)	15,339			(23,244		)
Net cash provided by operating activities	$	114,690		$	208,562		$	(93,872	)

The decrease in net cash provided by operating activities resulted primarily from the Pacific Khamsin and the Pacific Mistral being idle for the six months ended June 30, 2016.

The following table provides a comparison of our net cash used in investing activities for the six months ended June 30, 2016 and 2015:



	Six Months Ended June 30,
	2016			2015			Change
	(in thousands)
Cash flow from investing activities:
Capital expenditures	$	(41,677	)	$	(102,116	)	$	60,439
Net cash used in investing activities	$	(41,677	)	$	(102,116	)	$	60,439

The decrease in capital expenditures resulted primarily from no newbuild drillship construction activities in the first six months of 2016. Capital expenditures for the six months ended June 30, 2016 primarily consisted of the purchases of fleet spare equipment committed to in prior years to support our operations.

The following table provides a comparison of our net cash provided by (used in) financing activities for the six months ended June 30, 2016 and 2015:



	Six Months Ended June 30,
	2016			2015			Change
	(in thousands)
Cash flow from financing activities:
Net payments from shares issued under share-based compensation plan	$	(87	)	$	(419	)	$	332
Proceeds from long-term debt	235,000			265,000			(30,000		)
Payments on long-term debt	(52,875		)	(411,293		)	358,418
Payments for financing costs	—			(500		)	500
Purchases of treasury shares	—			(21,760		)	21,760
Net cash provided by (used in) financing activities	$	182,038		$	(168,972	)	$	351,010

The increase in cash from financing activities during the six months ended June 30, 2016, as compared to the same period in 2015, resulted from lower scheduled debt payments and no share repurchases, partially offset by lower drawdowns on

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our credit facilities. During the first six months of 2016, we drew $235.0 million under our 2013 Revolving Credit Facility, and during the first six months of 2015, we completed the final drawdowns under our Senior Secured Credit Facility.

Description of Indebtedness

7.25% Senior Secured Notes due 2017. In November 2012, Pacific Drilling V Limited, our indirect, wholly-owned subsidiary, completed a private placement to eligible purchasers of $500.0 million in aggregate principal amount of 7.25% senior secured U.S. dollar denominated notes due 2017 to fund the final construction costs related to the Pacific Khamsin. The 2017 Senior Secured Notes bear interest at 7.25% per annum, which is payable semiannually on June 1 and December 1, and mature on December 1, 2017.

Senior Secured Credit Facility Agreement. On February 19, 2013, Pacific Sharav S.à r.l. and Pacific Drilling VII Limited, and we, as guarantor, entered into the SSCF with a group of lenders to finance the construction, operation and other costs associated with the Pacific Sharav and the Pacific Meltem. In 2015, we completed the final drawdown under this facility, resulting in a cumulative total drawdown of $985.0 million. As of June 30, 2016, the outstanding balance under the SSCF was $817.2 million.

5.375% Senior Secured Notes due 2020. On June 3, 2013, we completed a private placement to eligible purchasers of $750.0 million in aggregate principal amount of 5.375% Senior Secured Notes due 2020. The 2020 Senior Secured Notes were sold at par, bear interest at 5.375% per annum, which is payable semiannually on June 1 and December 1, and mature on June 1, 2020.

Senior Secured Term Loan B due 2018. On June 3, 2013, we entered into a $750.0 million senior secured term loan. The Senior Secured Term Loan B matures on June 3, 2018.

2013 Revolving Credit Facility. On June 3, 2013, we entered into the 2013 Revolving Credit Facility which, as amended permits loans to be extended up to a maximum limit of $500.0 million and permits letters of credit to be issued up to a maximum sublimit of $300.0 million, subject to a $500.0 million overall facility limit. As of June 30, 2016, the outstanding balance under the 2013 Revolving Credit Facility was $285.0 million.

Covenants

For additional information, see Note 4 to our unaudited condensed consolidated financial statements included in this Form 6-K and Note 5 to our consolidated financial statements included in our 2015 Annual Report.

Customs Bonds

As of June 30, 2016, we were contingently liable under certain customs bonds totaling approximately $53.7 million issued as security in the normal course of our business. See Note 9 to our unaudited condensed consolidated financial statements.

Derivative Instruments and Hedging Activities

We may enter into derivative instruments from time to time to manage our exposure to fluctuations in interest rates and foreign exchange rates. We do not enter into derivative transactions for speculative purposes; however, for accounting purposes, certain transactions may not meet the criteria for hedge accounting. See Note 7 to our unaudited condensed consolidated financial statements.

Off-Balance Sheet Arrangements

Currently, we do not have any off-balance sheet arrangements.

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Contractual Obligations

The table below sets forth our contractual obligations as of June 30, 2016:



	Remaining six months		For the years ending December 31,
Contractual Obligations	2016		2017-2018		2019-2020		Thereafter		Total
	(in thousands)
Long-term debt^(a)	$	43,628	$	1,644,534	$	1,367,813	$	—	$	3,055,975
Interest on long-term debt^(b)	83,083		250,560		68,547		—		402,190
Operating leases	1,175		4,486		4,204		8,101		17,966
Purchase obligations^(c)	46,595		98		—		—		46,693
Total contractual obligations^(d)	$	174,481	$	1,899,678	$	1,440,564	$	8,101	$	3,522,824

__________________________________


(a)	Includes current maturities of long-term debt. Amounts are based on principal balances, excluding debt discounts.

(b)

Interest payments are based on our existing outstanding borrowings as of June 30, 2016. Amounts assume no refinancing of existing long-term debt and no prepayments. For fixed rate debt, interest has been calculated using stated rates. For variable rate LIBOR based debt, interest has been calculated using current LIBOR as of June 30, 2016 and includes the impact of our outstanding interest rate swaps.


(c)	Purchase obligations are agreements to purchase goods and services that are enforceable and legally binding and that specify all significant terms, including the quantities to be purchased, price provisions and the approximate timing of the transactions, which includes our purchase orders for goods and services entered into in the normal course of business.


(d)	Contractual obligations do not include approximately $28.9 million of liabilities from unrecognized tax benefits related to uncertain tax positions, inclusive of interest and penalties, included on our condensed consolidated balance sheet as of June 30, 2016. We are unable to specify with certainty the future periods in which we may be obligated to settle such amounts.

Some of the figures included in the table above are based on estimates and assumptions about these obligations, including their duration and other factors. The contractual obligations we will actually pay in future periods may vary from those reflected in the tables.

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Critical Accounting Estimates and Policies

The preparation of unaudited condensed consolidated financial statements in conformity with GAAP requires management to make certain estimates and assumptions. These estimates and assumptions impact the reported amounts of assets and liabilities, the disclosures of contingent assets and liabilities at the balance sheet date and the amounts of revenues and expenses recognized during the reporting period. On an ongoing basis, we evaluate our estimates and assumptions, including those related to allowance for doubtful accounts, financial instruments, depreciation of property and equipment, impairment of long-lived assets, long-term receivable, income taxes, share-based compensation and contingencies. We base our estimates and assumptions on historical experience and on various other factors we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results could differ from such estimates.

For a discussion of the critical accounting policies and estimates that we use in the preparation of our unaudited condensed consolidated financial statements, see Item 5, “Operating and Financial Review and Prospects—Critical Accounting Estimates and Policies” in our 2015 Annual Report. During the three and six months ended June 30, 2016, there have been no material changes to the judgments, assumptions and estimates upon which our critical accounting estimates are based. Significant accounting policies and recently issued accounting standards are discussed in Note 2 to our unaudited condensed consolidated financial statements in this Form 6-K and in Note 2 to our consolidated financial statements included in our 2015 Annual Report.

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FORWARD-LOOKING STATEMENTS

Certain statements and information contained in this Form 6-K constitute “forward-looking statements” within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, and are generally identifiable by the use of words such as “believe,” “estimate,” “expect,” “forecast,” “our ability to,” “plan,” “potential,” “projected,” “target,” “would,” or other similar words, which are generally not historical in nature. The forward-looking statements speak only as of the date hereof, and we undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

Our forward-looking statements express our current expectations or forecasts of possible future results or events, including our future financial and operational performance; revenue efficiency levels; market outlook; forecasts of trends; future client contract opportunities; contract dayrates; our business strategies and plans and objectives of management; estimated duration of client contracts; backlog; our ability to repay our debt; expected capital expenditures and projected costs and savings.

Although we believe that the assumptions and expectations reflected in our forward-looking statements are reasonable and made in good faith, these statements are not guarantees and actual future results may differ materially due to a variety of factors. These statements are subject to a number of risks and uncertainties, many of which are beyond our control.

Important factors that could cause actual results to differ materially from our expectations include: the global oil and gas market and its impact on demand for our services; the offshore drilling market, including reduced capital expenditures by our clients; changes in worldwide oil and gas supply and demand; rig availability and supply and demand for high-specification drillships and other drilling rigs competing with our fleet; costs related to stacking of rigs; our ability to enter into and negotiate favorable terms for new drilling contracts or extensions; our substantial level of indebtedness; possible cancellation, renegotiation, termination or suspension of drilling contracts as a result of market changes or other reasons; and the other risk factors described in our filings with the SEC, including our Annual Report on Form 20-F and Current Reports on Form 6-K. These documents are available through our website at www.pacificdrilling.com or through the SEC’s website at www.sec.gov.

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Item 3 — Quantitative and Qualitative Disclosure about Market Risk

We are exposed to certain market risks arising from the use of financial instruments in the ordinary course of business. These risks arise primarily as a result of potential changes in the fair market value of financial instruments that would result from adverse fluctuations in interest rates and foreign currency exchange rates as discussed below. We have entered, and in the future may enter, into derivative financial instrument transactions to manage or reduce market risk, but we do not enter into derivative financial instrument transactions for speculative or trading purposes.

Interest Rate Risk. We are exposed to changes in interest rates through our variable rate long-term debt. We use interest rate swaps to manage our exposure to interest rate risks. Interest rate swaps are used to convert floating rate debt obligations to a fixed rate in order to achieve an overall desired position of fixed and floating rate debt. As of June 30, 2016, our net exposure to floating interest rate fluctuations on our outstanding debt was $572.4 million, based on floating rate debt of $1,684.9 million less the $1,112.5 million notional principal of our floating to fixed interest rate swaps. A 1% increase or decrease to the overall variable interest rate charged to us would thus increase or decrease our interest expense by approximately $5.7 million on an annual basis as of June 30, 2016.

Foreign Currency Exchange Rate Risk. We are exposed to foreign exchange risk associated with our international operations. For a discussion of our foreign exchange risk, see Item 11, “Quantitative and Qualitative Disclosures About Market Risk” in our 2015 Annual Report. There have been no material changes to these previously reported matters during the three and six months ended June 30, 2016.

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PART II — OTHER INFORMATION

Item 1 — Legal Proceedings

See Note 9 to our unaudited condensed consolidated financial statements.

Item 1A — Risk Factors

In addition to the other information set forth in this report, you should carefully consider the risk factors previously disclosed under Item 3, “Risk Factors” in our 2015 Annual Report, which could materially affect our business, financial condition or future results. During the six months ended June 30, 2016, there have been no significant changes in our risk factors as described in our 2015 Annual Report.

Item 2 — Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3 — Defaults Upon Senior Securities

None.

Item 4 — Mine Safety Disclosures

Not applicable.

Item 5 — Other Information

Following the Reverse Stock Split as described in Note 2 to our unaudited condensed consolidated financial statements, at the close of trading on May 31, 2016, our common shares had a closing price per share and a 30-trading-day average closing price per share above $1.00 and accordingly, we regained compliance with the New York Stock Exchange continued listing standard.

Item 6 — Exhibits



Exhibit Number		Description
1.1*		Consolidated Articles of Association of Pacific Drilling S.A., dated June 24, 2016.



*	Filed herewith.

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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.




		Pacific Drilling S.A.
		(Registrant)

Dated:	August 8, 2016	By	/s/ Paul T. Reese
			Paul T. Reese
			Chief Financial Officer